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 September 30, 20172018
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 Company     X    
Gulf Power Company     X    
Mississippi Power Company     X    
Southern Power Company     X    
Southern Company Gas     X    
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ (Response applicable to all registrants.)
 
Registrant 
Description of
Common Stock
 Shares Outstanding at September 30, 20172018
The Southern Company Par Value $5 Per Share 1,003,627,6911,028,888,684
Alabama Power Company Par Value $40 Per Share 30,537,500
Georgia Power Company Without Par Value 9,261,500
Gulf Power Company Without Par Value 7,392,717
Mississippi Power Company Without Par Value 1,121,000
Southern Power Company Par Value $0.01 Per Share 1,000
Southern Company Gas Par Value $0.01 Per Share 100
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 20172018


  
Page
Number
   
DEFINITIONS
5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
89
   
 PART I—FINANCIAL INFORMATION 
Item 1.Financial Statements (Unaudited) 
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations 
 
The Southern Company and Subsidiary Companies
 
 
Condensed Consolidated Statements of Income
1112
 
Condensed Consolidated Statements of Comprehensive Income
1213
 
Condensed Consolidated Statements of Cash Flows
1314
 
Condensed Consolidated Balance Sheets
1415
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
1617
 
Alabama Power Company
 
 
Condensed Statements of Income
5761
 
Condensed Statements of Comprehensive Income
5761
 
Condensed Statements of Cash Flows
5862
 
Condensed Balance Sheets
5963
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
6165
 
Georgia Power Company
 
 
Condensed Statements of Income
7582
 
Condensed Statements of Comprehensive Income
7582
 
Condensed Statements of Cash Flows
7683
 
Condensed Balance Sheets
7784
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
7986
 
Gulf Power Company
 
 
Condensed Statements of Income
101113
 
Condensed Statements of Comprehensive Income
101113
 
Condensed Statements of Cash Flows
102114
 
Condensed Balance Sheets
103115
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
105117
 
Mississippi Power Company
 
 
Condensed Statements of IncomeOperations
120133
 
Condensed Statements of Comprehensive Income
120133
 
Condensed Statements of Cash Flows
121134
 
Condensed Balance Sheets
122135
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
124137
 
Southern Power Company and Subsidiary Companies
 
 
Condensed Consolidated Statements of Income
152158
 
Condensed Consolidated Statements of Comprehensive Income
152158
 
Condensed Consolidated Statements of Cash Flows
153159
 
Condensed Consolidated Balance Sheets
154160
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
156162
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 20172018


  Page
Number
 PART I—FINANCIAL INFORMATION (CONTINUED) 
 
Southern Company Gas and Subsidiary Companies
 
 
Condensed Consolidated Statements of Income
171177
 
Condensed Consolidated Statements of Comprehensive Income
172177
 
Condensed Consolidated Statements of Cash Flows
173178
 
Condensed Consolidated Balance Sheets
174179
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
176181
 
Notes to the Condensed Financial Statements
206207
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
5559
Item 4.
Controls and Procedures
5559
   
 PART II—OTHER INFORMATION 
Item 1.
Legal Proceedings
279286
Item 1A.
Risk Factors
279286
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.
Exhibits
282291
 
Signatures
286295

Table of Contents

DEFINITIONS
TermMeaning
  
2012 MPSC CPCN OrderA detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
2013 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
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
Baseload ActBechtelState of Mississippi legislation designed to enhanceBechtel Power Corporation, the Mississippi PSC's authority to facilitate developmentprimary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel AgreementThe October 23, 2017 construction of baseload generation incompletion agreement between the State of MississippiVogtle Owners and Bechtel
CCRCoal combustion residuals
Chattanooga GasChattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
Clean Power Plan
Final action published by the EPA in 2015 that established guidelines for states to develop
plans to meet EPA-mandated CO2emission rates or emission reduction goals for existing
electric generating units
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 formerly known as South Mississippi Electric Power Association (SMEPA)
CPCNCertificate of public convenience and necessity
Customer RefundsRefunds issued to Georgia Power customers in 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement
CWIPConstruction work in progress
Dalton PipelineA 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 Planenvironmental 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 Loan Guarantee Programof the Energy Policy Act of 2005
EPAU.S. Environmental Protection Agency
EPC ContractorWestinghouse and its affiliate, WECTEC (formerly known as CB&I Stone & Webster,Global Project Services Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.; 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, 2016,2017, as applicable
GAAPU.S. generally accepted accounting principles
Georgia PowerGeorgia Power Company
GHGGreenhouse gas

Table of Contents

DEFINITIONS
(continued)
TermMeaning
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
Gulf PowerGulf Power Company
Heating Degree DaysA measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Horizon PipelineHorizon Pipeline Company, LLC

DEFINITIONS
(continued)
TermMeaning
IGCCIntegrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IICIntercompany interchange contract
Illinois CommissionIllinois Commerce Commission the state regulatory agency for Nicor Gas
IRCInterim Assessment AgreementInternal Revenue Code of 1986, as amendedAgreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing
IRSInternal Revenue Service
ITCInvestment tax credit
Kemper IGCCJEAMississippi Power's IGCC project in Kemper County, MississippiJacksonville 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
MATS ruleMEAGMercury and Air Toxics Standards ruleMunicipal 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
Mirror CWIPA regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order
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' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas, Company, and Elkton Gas)Gas as of June 30, 2018) (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas as of July 29, 2018)
NCCRGeorgia Power's Nuclear Construction Cost Recovery
New Jersey BPUNextEra EnergyNew Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown GasNextEra 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.
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

Table of Contents

DEFINITIONS
(continued)
Piedmont
Piedmont Natural
TermMeaning
Pivotal Home SolutionsNicor Energy Services Company, until June 4, 2018 a wholly-owned subsidiary of Southern Company Gas, Company, Inc.doing business as Pivotal Home Solutions
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
Plant Vogtle Units 3 and 4Two new nuclear generating units under construction at Georgia Power's Plant Vogtle
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

DEFINITIONS
(continued)
TermMeaning
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
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
ROEReturn on equity
S&PS&P Global Ratings, a division of S&P Global Inc.
scrubberFlue gas desulfurization system
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, (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, (as of May 9, 2016), and other subsidiaries
Southern NuclearSouthern Nuclear Operating Company, Inc.
Southern PowerSouthern Power Company and its subsidiaries
SouthStarSPSHSouthStar Energy Services,SP Solar Holdings I, LP
SP WindSP Wind Holdings II, LLC
STRIDETax Reform LegislationAtlanta Gas Light's Strategic Infrastructure DevelopmentThe Tax Cuts and Enhancement programJobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018
ToshibaToshiba Corporation, 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
TritonTriton Container Investments, LLC
VCMVogtle Construction Monitoring
Virginia CommissionVirginia State Corporation Commission the state regulatory agency for Virginia Natural Gas
Virginia Natural GasVirginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas

Table of Contents

DEFINITIONS
(continued)
TermMeaning
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
WECTECWECTEC Global Project Services Inc.
WestinghouseWestinghouse Electric Company LLC

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;
current and future litigation, 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;
variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
effects of inflation;
the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);
the impact of any inability or other failure of Toshiba to perform its obligations under the Toshiba Guarantee, including any effect on the construction of Plant Vogtle Units 3 and 4;
the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of 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;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;




CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, costs of modernization efforts, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of construction projects, completion of announced 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," "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 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 only recently began 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;

Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
actions related to cost recovery for the Kemper IGCC, including ongoing settlement discussions, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, and related legal or regulatory proceedings;
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 Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction and the ability of other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases;
in the event Georgia Power becomes obligated to provide funding to MEAG with respect to the portion of MEAG's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;
litigation or other disputes related to the Kemper County energy facility;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the inherent risks involved in transporting and storing natural gas;
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition bydispositions of Gulf Power, Southern Power's plants located in Florida, and the Mankato natural gas facility and the proposed sale of a wholly-owned subsidiary ofnoncontrolling interest in Southern Company Gas of Elizabethtown Gas and Elkton Gas,Power's wind facilities, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;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 terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.

Table of Contents

THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail electric revenues$4,615
 $4,808
 $11,786
 $11,932
$4,605
 $4,615
 $11,913
 $11,786
Wholesale electric revenues718
 613
 1,867
 1,455
693
 718
 1,923
 1,867
Other electric revenues168
 181
 510
 529
170
 168
 509
 510
Natural gas revenues532
 518
 2,746
 518
Natural gas revenues (includes alternative revenue programs of
$5, $-, $(23), and $9, respectively)		492
 532
 2,806
 2,746
Other revenues168
 144
 494
 281
199
 168
 1,007
 494
Total operating revenues6,201
 6,264
 17,403
 14,715
6,159
 6,201
 18,158
 17,403
Operating Expenses:              
Fuel1,285
 1,400
 3,372
 3,334
1,310
 1,285
 3,514
 3,372
Purchased power256
 227
 646
 581
257
 256
 760
 646
Cost of natural gas134
 133
 1,085
 133
104
 134
 1,053
 1,085
Cost of other sales90
 84
 293
 161
120
 90
 688
 293
Other operations and maintenance1,287
 1,411
 3,918
 3,616
1,404
 1,341
 4,217
 4,100
Depreciation and amortization767
 695
 2,236
 1,805
787
 767
 2,338
 2,236
Taxes other than income taxes303
 309
 941
 821
319
 303
 990
 941
Estimated loss on Kemper IGCC34
 88
 3,155
 222
Estimated loss on plants under construction1
 34
 1,105
 3,155
Gain on dispositions, net(353) —
 (317) (19)
Impairment charges36
 —
 197
 —
Total operating expenses4,156
 4,347
 15,646
 10,673
3,985
 4,210
 14,545
 15,809
Operating Income2,045
 1,917
 1,757
 4,042
2,174
 1,991
 3,613
 1,594
Other Income and (Expense):              
Allowance for equity funds used during construction18
 52
 133
 150
36
 18
 99
 133
Earnings from equity method investments32
 29
 100
 28
36
 32
 108
 100
Interest expense, net of amounts capitalized(407) (374) (1,248) (913)(458) (407) (1,386) (1,248)
Other income (expense), net11
 (8) 2
 (66)57
 65
��195
 165
Total other income and (expense)(346) (301) (1,013) (801)(329) (292) (984) (850)
Earnings Before Income Taxes1,699
 1,616
 744
 3,241
1,845
 1,699
 2,629
 744
Income taxes590
 439
 317
 917
623
 590
 598
 317
Consolidated Net Income1,109
 1,177
 427
 2,324
1,222
 1,109
 2,031
 427
Less:       
Dividends on preferred and preference stock of subsidiaries10
 11
 32
 34
4
 10
 12
 32
Net income attributable to noncontrolling interests30
 27
 48
 39
54
 30
 71
 48
Consolidated Net Income Attributable to
Southern Company
$1,069
 $1,139
 $347
 $2,251
$1,164
 $1,069
 $1,948
 $347
Common Stock Data:              
Earnings per share —       
Earnings per share -       
Basic$1.07
 $1.18
 $0.35
 $2.40
$1.14
 $1.07
 $1.92
 $0.35
Diluted$1.06
 $1.17
 $0.35
 $2.38
$1.13
 $1.06
 $1.91
 $0.35
Average number of shares of common stock outstanding (in millions)              
Basic1,003
 968
 998
 940
1,023
 1,003
 1,016
 998
Diluted1,010
 975
 1,005
 945
1,029
 1,010
 1,021
 1,005
Cash dividends paid per share of common stock$0.5800
 $0.5600
 $1.7200
 $1.6625
$0.60
 $0.58
 $1.78
 $1.72
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Consolidated Net Income$1,222
 $1,109
 $2,031
 $427
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of
$(4), $15, $(6), and $32, respectively		(11) 25
 (19) 54
Reclassification adjustment for amounts included in net income,
net of tax of $5, $(10), $21, and $(36), respectively		14
 (17) 60
 (59)
Pension and other postretirement benefit plans:       
Reclassification adjustment for amounts included in net income,
net of tax of $3, $1, $4, and $2, respectively		8
 1
 11
 3
Total other comprehensive income (loss)11
 9
 52
 (2)
Comprehensive Income1,233
 1,118
 2,083
 425
Dividends on preferred and preference stock of subsidiaries4
 10
 12
 32
Comprehensive income attributable to noncontrolling interests54
 30
 71
 48
Consolidated Comprehensive Income Attributable to
Southern Company		$1,175
 $1,078
 $2,000
 $345
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.


Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Consolidated net income$2,031
 $427
Adjustments to reconcile consolidated net income to net cash provided from operating activities —    
Depreciation and amortization, total2,647
 2,564
Deferred income taxes(286) 15
Allowance for equity funds used during construction(99) (133)
Pension, postretirement, and other employee benefits(60) (64)
Settlement of asset retirement obligations(160) (137)
Stock based compensation expense108
 95
Estimated loss on plants under construction1,081
 3,148
Gain on dispositions, net(324) (22)
Impairment charges197
 —
Other, net(21) (80)
Changes in certain current assets and liabilities —   
-Receivables37
 423
-Prepayments14
 (39)
-Natural gas for sale87
 —
-Other current assets(90) (66)
-Accounts payable(248) (467)
-Accrued taxes839
 157
-Accrued compensation(138) (230)
-Retail fuel cost over recovery36
 (211)
-Other current liabilities(67) (129)
Net cash provided from operating activities5,584
 5,251
Investing Activities:   
Business acquisitions, net of cash acquired(64) (1,016)
Property additions(5,793) (5,242)
Nuclear decommissioning trust fund purchases(846) (585)
Nuclear decommissioning trust fund sales840
 580
Dispositions2,773
 66
Cost of removal, net of salvage(252) (208)
Change in construction payables, net91
 120
Investment in unconsolidated subsidiaries(93) (134)
Payments pursuant to LTSAs(157) (189)
Other investing activities1
 (77)
Net cash used for investing activities(3,500) (6,685)
Financing Activities:   
Decrease in notes payable, net(1,225) (515)
Proceeds —   
Long-term debt1,950
 4,068
Common stock878
 613
Preferred stock—
 250
Short-term borrowings3,150
 1,263
Redemptions and repurchases —   
Long-term debt(4,498) (1,981)
Preferred and preference stock—
 (150)
Short-term borrowings(1,800) (409)
Distributions to noncontrolling interests(86) (89)
Capital contributions from noncontrolling interests1,333
 79
Payment of common stock dividends(1,805) (1,716)
Other financing activities(237) (113)
Net cash provided from (used for) financing activities(2,340) 1,300
Net Change in Cash, Cash Equivalents, and Restricted Cash(256) (134)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period2,147
 1,992
Cash, Cash Equivalents, and Restricted Cash at End of Period$1,891
 $1,858
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $53 and $72 capitalized for 2018 and 2017, respectively)$1,402
 $1,286
Income taxes, net137
 (187)
Noncash transactions — Accrued property additions at end of period1,125
 805
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $1,847
 $2,130
Receivables —    
Customer accounts receivable 1,730
 1,806
Energy marketing receivables 498
 607
Unbilled revenues 738
 810
Under recovered fuel clause revenues 105
 171
Other accounts and notes receivable 690
 698
Accumulated provision for uncollectible accounts (33) (44)
Materials and supplies 1,418
 1,438
Fossil fuel for generation 390
 594
Natural gas for sale 486
 595
Prepaid expenses 354
 452
Other regulatory assets, current 522
 604
Assets held for sale, current 407
 12
Other current assets 232
 199
Total current assets 9,384
 10,072
Property, Plant, and Equipment:    
In service 100,672
 103,542
Less: Accumulated depreciation 30,739
 31,457
Plant in service, net of depreciation 69,933
 72,085
Nuclear fuel, at amortized cost 844
 883
Construction work in progress 7,655
 6,904
Total property, plant, and equipment 78,432
 79,872
Other Property and Investments:    
Goodwill 5,315
 6,268
Equity investments in unconsolidated subsidiaries 1,569
 1,513
Other intangible assets, net of amortization of $225 and $186
at September 30, 2018 and December 31, 2017, respectively		 674
 873
Nuclear decommissioning trusts, at fair value 1,872
 1,832
Leveraged leases 794
 775
Miscellaneous property and investments 258
 249
Total other property and investments 10,482
 11,510
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 792
 825
Unamortized loss on reacquired debt 328
 206
Other regulatory assets, deferred 6,196
 6,943
Assets held for sale 4,667
 —
Other deferred charges and assets 1,436
 1,577
Total deferred charges and other assets 13,419
 9,551
Total Assets $111,717
 $111,005
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 STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months Ended September 30, For the Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions) (in millions)
Consolidated Net Income$1,109
 $1,177
 $427
 $2,324
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of $15, $12, $32, and $(74),
respectively		25
 19
 54
 (118)
Reclassification adjustment for amounts included in net income,
net of tax of $(10), $2, $(36), and $13, respectively		(17) 2
 (59) 20
Pension and other postretirement benefit plans:       
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $2, respectively		1
 1
 3
 3
Total other comprehensive income (loss)9
 22
 (2) (95)
Comprehensive Income1,118
 1,199
 425
 2,229
Less:       
Dividends on preferred and preference stock of subsidiaries10
 11
 32
 34
Comprehensive income attributable to noncontrolling interests30
 27
 48
 39
Consolidated Comprehensive Income Attributable to
   Southern Company
$1,078
 $1,161
 $345
 $2,156
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 STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months Ended September 30,
 2017 2016
 (in millions)
Operating Activities:   
Consolidated net income$427
 $2,324
Adjustments to reconcile consolidated net income to net cash provided from operating activities —    
Depreciation and amortization, total2,564
 2,109
Deferred income taxes15
 (22)
Allowance for equity funds used during construction(133) (150)
Pension, postretirement, and other employee benefits(64) (158)
Settlement of asset retirement obligations(137) (117)
Hedge settlements—
 (236)
Estimated loss on Kemper IGCC3,148
 222
Other, net(8) (1)
Changes in certain current assets and liabilities —   
-Receivables426
 (458)
-Fossil fuel for generation59
 204
-Natural gas for sale, net of temporary LIFO liquidation—
 (222)
-Other current assets(164) (112)
-Accounts payable(467) (9)
-Accrued taxes157
 1,062
-Accrued compensation(230) (122)
-Retail fuel cost over recovery(211) (106)
-Other current liabilities(129) 88
Net cash provided from operating activities5,253
 4,296
Investing Activities:   
Business acquisitions, net of cash acquired(1,032) (9,513)
Property additions(5,242) (5,252)
Investment in restricted cash(16) (750)
Distribution of restricted cash33
 746
Nuclear decommissioning trust fund purchases(585) (838)
Nuclear decommissioning trust fund sales580
 832
Cost of removal, net of salvage(208) (155)
Change in construction payables, net120
 (259)
Investment in unconsolidated subsidiaries(134) (1,421)
Payments pursuant to LTSAs(189) (125)
Other investing activities(14) 95
Net cash used for investing activities(6,687) (16,640)
Financing Activities:   
Increase (decrease) in notes payable, net(515) 655
Proceeds —   
Long-term debt4,068
 14,091
Common stock613
 3,265
Preferred stock250
 —
Short-term borrowings1,263
 —
Redemptions and repurchases —   
Long-term debt(1,981) (2,405)
Preferred and preference stock(150) —
Short-term borrowings(409) (475)
Distributions to noncontrolling interests(89) (22)
Capital contributions from noncontrolling interests79
 367
Purchase of membership interests from noncontrolling interests—
 (129)
Payment of common stock dividends(1,716) (1,553)
Other financing activities(113) (185)
Net cash provided from financing activities1,300
 13,609
Net Change in Cash and Cash Equivalents(134) 1,265
Cash and Cash Equivalents at Beginning of Period1,975
 1,404
Cash and Cash Equivalents at End of Period$1,841
 $2,669
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $72 and $94 capitalized for 2017 and 2016, respectively)$1,286
 $766
Income taxes, net(187) (151)
Noncash transactions — Accrued property additions at end of period805
 578
The accompanying notes as they relate to Southern Company are an integral partTable of these condensed consolidated financial statements.Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30, 2017 At December 31, 2016
  (in millions)
Current Assets:    
Cash and cash equivalents $1,841
 $1,975
Receivables —    
Customer accounts receivable 1,744
 1,583
Energy marketing receivables 427
 623
Unbilled revenues 595
 706
Under recovered fuel clause revenues 62
 —
Income taxes receivable, current 138
 544
Other accounts and notes receivable 578
 377
Accumulated provision for uncollectible accounts (43) (43)
Materials and supplies 1,499
 1,462
Fossil fuel for generation 571
 689
Natural gas for sale 631
 631
Prepaid expenses 365
 364
Other regulatory assets, current 585
 581
Other current assets 209
 230
Total current assets 9,202
 9,722
Property, Plant, and Equipment:    
In service 102,014
 98,416
Less: Accumulated depreciation 31,164
 29,852
Plant in service, net of depreciation 70,850
 68,564
Nuclear fuel, at amortized cost 865
 905
Construction work in progress 8,026
 8,977
Total property, plant, and equipment 79,741
 78,446
Other Property and Investments:    
Goodwill 6,267
 6,251
Equity investments in unconsolidated subsidiaries 1,637
 1,549
Other intangible assets, net of amortization of $156 and $62
at September 30, 2017 and December 31, 2016, respectively		 902
 970
Nuclear decommissioning trusts, at fair value 1,783
 1,606
Leveraged leases 788
 774
Miscellaneous property and investments 236
 270
Total other property and investments 11,613
 11,420
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 1,318
 1,629
Unamortized loss on reacquired debt 210
 223
Other regulatory assets, deferred 6,718
 6,851
Other deferred charges and assets 1,513
 1,406
Total deferred charges and other assets 9,759
 10,109
Total Assets $110,315
 $109,697
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 September 30, 2017 At December 31, 2016 At September 30, 2018 At December 31, 2017
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $3,505
 $2,587
 $3,013
 $3,892
Notes payable 2,579
 2,241
 2,564
 2,439
Energy marketing trade payables 451
 597
 521
 546
Accounts payable 2,353
 2,228
 2,246
 2,530
Customer deposits 550
 558
 524
 542
Accrued taxes —    
Accrued income taxes 176
 193
Unrecognized tax benefits 17
 385
Other accrued taxes 690
 667
Accrued taxes 1,060
 636
Accrued interest 443
 518
 422
 488
Accrued compensation 703
 915
 800
 959
Asset retirement obligations, current 245
 378
 348
 351
Acquisitions payable —
 489
Other regulatory liabilities, current 139
 236
 349
 337
Liabilities held for sale, current 355
 —
Other current liabilities 752
 925
 763
 874
Total current liabilities 12,603
 12,917
 12,965
 13,594
Long-term Debt 44,042
 42,629
 41,425
 44,462
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 14,321
 14,092
 6,035
 6,842
Deferred credits related to income taxes 6,651
 7,256
Accumulated deferred ITCs 2,290
 2,228
 2,377
 2,267
Employee benefit obligations 2,139
 2,299
 2,017
 2,256
Asset retirement obligations, deferred 4,356
 4,136
 5,817
 4,473
Accrued environmental remediation 269
 389
Other cost of removal obligations 2,708
 2,748
 2,330
 2,684
Other regulatory liabilities, deferred 449
 476
 153
 239
Liabilities held for sale 2,835
 —
Other deferred credits and liabilities 1,048
 1,278
 454
 691
Total deferred credits and other liabilities 27,311
 27,257
 28,938
 27,097
Total Liabilities 83,956
 82,803
 83,328
 85,153
Redeemable Preferred Stock of Subsidiaries 361
 118
 324
 324
Redeemable Noncontrolling Interests 59
 164
Stockholders' Equity:        
Common Stockholders' Equity:        
Common stock, par value $5 per share —        
Authorized — 1.5 billion shares        
Issued — September 30, 2017: 1.0 billion shares    
— December 31, 2016: 991 million shares    
Treasury — September 30, 2017: 0.9 million shares    
— December 31, 2016: 0.8 million shares    
Issued — 1.0 billion shares    
Treasury — September 30, 2018: 1.0 million shares    
— December 31, 2017: 0.9 million shares    
Par value 5,018
 4,952
 5,140
 5,038
Paid-in capital 10,300
 9,661
 10,905
 10,469
Treasury, at cost (35) (31) (39) (36)
Retained earnings 8,981
 10,356
 9,048
 8,885
Accumulated other comprehensive loss (182) (180) (177) (189)
Total Common Stockholders' Equity 24,082
 24,758
 24,877
 24,167
Preferred and Preference Stock of Subsidiaries 462
 609
Noncontrolling Interests 1,395
 1,245
 3,188
 1,361
Total Stockholders' Equity 25,939
 26,612
 28,065
 25,528
Total Liabilities and Stockholders' Equity $110,315
 $109,697
 $111,717
 $111,005
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 20172018 vs. THIRD QUARTER 20162017
AND
YEAR-TO-DATE 20172018 vs. YEAR-TO-DATE 20162017


OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary businesses of electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. During the second quarter 2018, Southern Power completed the sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. Southern Company Gas distributes natural gas through its natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. In July 2018, Southern Company'sCompany Gas completed sales of three of its natural gas distribution utilities. During the second quarter 2018, Southern Company Gas also completed the sale of Pivotal Home Solutions. The Southern Company system's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K. See FUTURE EARNINGS POTENTIAL and Note (J) to the Condensed Financial Statements herein for additional information regarding disposition activity.
On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to certain adjustments. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions. 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.
In 2018, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Atlanta Gas Light, and Nicor Gas reached agreements with their respective state PSCs or other applicable state regulatory agencies relating to the regulatory impacts of the Tax Reform Legislation, which, for some companies, included capital structure adjustments expected to help mitigate the potential adverse impacts to certain of their credit metrics. See Note (B) to the Condensed Financial Statements under "Regulatory Matters" herein for additional information regarding state PSC or other regulatory agency actions related to the Tax Reform Legislation. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). 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 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). 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 did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast (or any related financing costs) in the nineteenth VCM report filed with the Georgia PSC 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.
As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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 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. Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain provisions of the Vogtle Owner Term Sheet.
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 September 2018, the DOE extended the conditional commitment to March 31, 2019. 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.
The ultimate outcome of these matters cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS
Net Income
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$95 8.9 $1,601 N/M
N/M - Not meaningful
Consolidated net income attributable to Southern Company was $1.2 billion ($1.14 per share) for the third quarter 2018 compared to $1.1 billion ($1.07 per share) for the corresponding period in 2017. The increase was primarily due to lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017. These increases were partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and an increase in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $1.9 billion ($1.92 per share) for year-to-date 2018 compared to $347 million ($0.35 per share) for the corresponding period in 2017. The increase was primarily due to charges of $3.2 billion ($2.2 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 increase 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 and third quarters 2018 compared to the corresponding periods in 2017, partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and impairment charges at Southern Power and Southern Company Gas, primarily related to the dispositions described in Note (J) to the Condensed Financial Statements herein.
Retail Electric Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(10) (0.2) $127 1.1
In the third quarter 2018, retail electric revenues were $4.61 billion compared to $4.62 billion for the corresponding period in 2017. For year-to-date 2018, retail electric revenues were $11.9 billion compared to $11.8 billion for the corresponding period in 2017.
Details of the changes in retail electric revenues were as follows:
  Third Quarter 2018 Year-to-Date 2018
  (in millions) (% change) (in millions) (% change)
Retail electric – prior year $4,615
   $11,786
  
Estimated change resulting from –        
Rates and pricing (198) (4.2) (444) (3.8)
Sales growth 43
 0.9
 65
 0.6
Weather 80
 1.7
 297
 2.5
Fuel and other cost recovery 65
 1.4
 209
 1.8
Retail electric – current year $4,605
 (0.2)% $11,913
 1.1 %
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as regulatory liabilities for future
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customer bill credits related to the Tax Reform Legislation and decreases in revenues recognized under the NCCR tariff at Georgia Power. The year-to-date 2018 decrease was partially offset by higher contributions from variable demand-driven pricing from commercial and industrial customers at Georgia Power.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " – Georgia Power – Rate Plans," and " – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. In the third quarter and year-to-date 2018, weather-adjusted residential KWH sales increased 1.2% and 0.8%, respectively, and weather-adjusted commercial KWH sales increased 0.8% and 0.6%, respectively, primarily due to customer growth. Industrial KWH sales increased 2.4% and 1.9% in the third quarter and year-to-date 2018, respectively, primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, partially offset by decreased sales in the chemicals and paper sectors, primarily due to customer maintenance outages and on-site cogeneration.
Fuel and other cost recovery revenues increased $65 million and $209 million in the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to higher energy sales resulting from colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017. 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
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(25) (3.5) $56 3.0
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the third quarter 2018, wholesale electric revenues were $693 million compared to $718 million for the corresponding period in 2017. This decrease was related to a $20 million decrease in energy revenues and a $5 million decrease in capacity revenues. The decrease in energy revenues is primarily related to a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the Shared Services Agreement
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(SSA) between Mississippi Power and Cooperative Energy. These decreases were partially offset by an increase in revenues at Southern Power from new natural gas PPAs from existing facilities, an increase in sales from renewable facilities, and an increase in fuel costs that are contractually recovered through PPAs.
For year-to-date 2018, wholesale electric revenues were $1.92 billion compared to $1.87 billion for the corresponding period in 2017. This increase was related to a $70 million increase in energy revenues, partially offset by a $14 million decrease in capacity revenues. The increase in energy revenues primarily related to Southern Power included revenues from new natural gas PPAs from existing facilities, an increase in fuel costs that are contractually recovered through PPAs, and an increase in sales from renewable facilities. These increases were partially offset by a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the SSA between Mississippi Power and Cooperative Energy.
Natural Gas Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(40) (7.5) $60 2.2
In the third quarter 2018, natural gas revenues were $492 million compared to $532 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues were $2.8 billion compared to $2.7 billion for the corresponding period in 2017.
Details of the changes in natural gas revenues were as follows:
 Third Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Natural gas revenues – prior year$532
   $2,746
  
Estimated change resulting from –       
Infrastructure replacement programs and base rate changes—
 —
 53
 1.9
Gas costs and other cost recovery(16) (3.0) (24) (0.9)
Weather1
 0.2
 17
 0.6
Wholesale gas services17
 3.2
 46
 1.7
Dispositions(*)
(43) (8.1) (30) (1.1)
Other1
 0.2
 (2) —
Natural gas revenues – current year$492
 (7.5)% $2,806
 2.2 %
(*)
Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased for year-to-date 2018 due to continued investments recovered through infrastructure replacement programs and 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 in the third quarter 2018 decreased primarily due to reduced natural gas prices during the third quarter 2018 compared to the corresponding period in 2017 and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues attributable to gas costs and other cost recovery for year-to-date 2018 decreased due to reduced natural gas prices during 2018 compared to the corresponding period in 2017, partially offset by increased volumes of natural gas sold in 2018 as a result of colder weather, as determined by Heating Degree Days.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and Southern Company Gas' gas marketing services customers in Georgia and Illinois.
Revenues attributable to Southern Company Gas' wholesale gas services business increased primarily due to increased commercial activity, partially offset by derivative losses.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations.
See Note (B) to the Condensed Financial Statements herein under "Regulatory Matters – Southern Company Gas" for additional information.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$31 18.5 $513 103.8
In the third quarter 2018, other revenues were $199 million compared to $168 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $1.0 billion compared to $494 million for the corresponding period in 2017. These increases were related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure, partially offset by a decrease in revenues resulting from the sale of Pivotal Home Solutions on June 4, 2018 at Southern Company Gas. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico. Additionally, these increases reflect $21 million and $40 million of revenues in the third quarter and year-to-date 2018, respectively, from unregulated sales of products and services that were reclassified to 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 the adoption of ASC 606.
Fuel and Purchased Power Expenses
 Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
 (change in millions) (% change) (change in millions) (% change)
Fuel$25
 1.9 $142
 4.2
Purchased power1
 0.4 114
 17.6
Total fuel and purchased power expenses$26
   $256
  
In the third quarter 2018, total fuel and purchased power expenses were $1.6 billion compared to $1.5 billion for the corresponding period in 2017. The increase was primarily the result of a $68 million increase in the volume of KWHs generated and purchased, partially offset by a $42 million decrease in the average cost of fuel and purchased power.
For year-to-date 2018, total fuel and purchased power expenses were $4.3 billion compared to $4.0 billion for the corresponding period in 2017. The increase was primarily the result of a $300 million increase in the volume of KWHs generated and purchased, partially offset by a $74 million net decrease in the average cost of fuel and purchased power. In addition, fuel expense increased $30 million for 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" and " – Alabama Power – Accounting Order" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
Details of the Southern Company system's generation and purchased power were as follows:
 Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in billions of KWHs)
56 55 153 147
Total purchased power (in billions of KWHs)
6 6 16 14
Sources of generation (percent) —
       
Gas47 47 46 46
Coal32 31 30 30
Nuclear14 15 15 16
Hydro2 2 3 2
Other5 5 6 6
Cost of fuel, generated (in cents per net KWH)(a) —
       
Gas2.78 2.92 2.79 2.93
Coal2.75 2.75 2.79 2.82
Nuclear0.81 0.80 0.80 0.80
Average cost of fuel, generated (in cents per net KWH)(a)
2.47 2.52 2.47 2.51
Average cost of purchased power (in cents per net KWH)(b)
5.32 5.36 5.52 5.32
(a)For year-to-date 2018, cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.
(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2018, fuel expense was $1.31 billion compared to $1.29 billion for the corresponding period in 2017. The increase was primarily due to a 7.5% increase in the volume of KWHs generated by natural gas and a 1.3% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated.
For year-to-date 2018, fuel expense was $3.5 billion compared to $3.4 billion for the corresponding period in 2017. The increase was primarily due to a 9.3% increase in the volume of KWHs generated by natural gas and a 4.1% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated and a 1.1% decrease in the average cost of coal per KWH generated.
Purchased Power
For year-to-date 2018, purchased power expense was $760 million compared to $646 million for the corresponding period in 2017. The increase was primarily due to a 10.5% increase in the volume of KWHs purchased and a 3.8% increase in the average cost per KWH purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Natural Gas
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(30) (22.4) $(32) (2.9)
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 75% and 83% of total cost of natural gas for the third quarter and year-to-date 2018, respectively.
In the third quarter 2018, cost of natural gas was $104 million compared to $134 million for the corresponding period in 2017. The decrease reflects $14 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in the third quarter 2018 as a result of fewer gas distribution customers, and a 3.2% decrease in natural gas prices during the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, cost of natural gas was $1.05 billion compared to $1.09 billion for the corresponding period in 2017. The decrease reflects $8 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in 2018 as a result of fewer gas distribution customers, as well as an 8.4% decrease in natural gas prices during 2018, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather compared to the corresponding period in 2017.
Cost of Other Sales
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$30 33.3 $395 134.8
In the third quarter 2018, cost of other sales was $120 million compared to $90 million for the corresponding period in 2017. For year-to-date 2018, cost of other sales was $688 million compared to $293 million for the corresponding period in 2017. These increases were related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico.
Other Operations and Maintenance Expenses
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$63 4.7 $117 2.9
In the third quarter 2018, other operations and maintenance expenses were $1.4 billion compared to $1.3 billion for the corresponding period in 2017. The increase was primarily due to a $22 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $21 million of disposition-related costs at Southern Company Gas. The increase also reflects $21 million of expenses from unregulated sales of products and services that were reclassified to 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.
For year-to-date 2018, other operations and maintenance expenses were $4.2 billion compared to $4.1 billion for the corresponding period in 2017. The increase was primarily due to a $60 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $29 million of disposition-related costs at
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company Gas. The increase also reflects $51 million of expenses from unregulated sales of products and services that were reclassified to 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. These increases were partially offset by a $32.5 million charge in the first quarter 2017 related to the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the settlement of Gulf Power's 2017 rate case. 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.
See Note (A) to the Condensed Financial Statements herein for additional information regarding the adoption of ASC 606.
Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$20 2.6 $102 4.6
In the third quarter 2018, depreciation and amortization was $787 million compared to $767 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $2.3 billion compared to $2.2 billion for the corresponding period in 2017. These increases primarily reflect increases of $18 million and $76 million for the third quarter and year-to-date 2018, respectively, related to additional plant in service. Additionally, the year-to-date 2018 increase was due to $34 million in depreciation credits recognized in 2017, 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
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$16 5.3 $49 5.2
In the third quarter 2018, taxes other than income taxes were $319 million compared to $303 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $990 million compared to $941 million for the corresponding period in 2017. These increases were primarily due to increased property taxes at the traditional electric operating companies and investment capital taxes at Southern Company Gas. Also contributing to the year-to-date 2018 increase was an increase in municipal franchise fees primarily related to higher retail revenues at Georgia Power and an increase in revenue tax expenses as a result of higher revenues at Southern Company Gas.
Estimated Loss on Plants Under Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(33) (97.1) $(2,050) (65.0)
In the third quarter 2018, estimated loss on plants under construction was $1 million compared to $34 million for the corresponding period in 2017. For year-to-date 2018, estimated loss on plants under construction was $1.1 billion compared to $3.2 billion for the corresponding period in 2017. The third quarter 2018 decrease was primarily due to lower costs associated with abandonment and related closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power. The year-to-date 2018 decrease was primarily due to revisions to the estimated construction costs for, and subsequent suspension in June 2017 of, the Kemper IGCC at Mississippi
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Power, partially offset by charges in 2018 related to Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4.
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.
Gain on Dispositions, Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$353 N/M $298 N/M
N/M - Not meaningful
In the third quarter and year-to-date 2018, a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax), respectively, were recorded related to the Southern Company Gas Dispositions. The year-to-date 2018 increase in gain on dispositions, net was partially offset by a $19 million decrease in gains from sales of integrated transmission system assets at Georgia Power. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information regarding related income taxes which substantially offset the gains for the Southern Company Gas Dispositions.
Impairment Charges
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$36 N/M $197 N/M
N/M - Not meaningful
Southern Power recorded a $36 million asset impairment charge in the third quarter 2018 on wind turbine equipment held for development projects and a $119 million asset impairment charge in the second quarter 2018 in contemplation of the sale of its Florida plants. Additionally, Southern Company Gas recorded a goodwill impairment charge of $42 million during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions.
See Notes (A) and (J) to the Condensed Financial Statements herein under "Goodwill and Other Intangible Assets" and under "Southern Power – Sale of Florida Plants" and "Southern Company Gas," respectively, for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$18 100.0 $(34) (25.6)
In the third quarter 2018, AFUDC equity was $36 million compared to $18 million in the corresponding period in 2017. The increase was primarily due to a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.
For year-to-date 2018, AFUDC equity was $99 million compared to $133 million in the corresponding period in 2017. The decrease primarily resulted from Mississippi Power's suspension of the Kemper IGCC construction in June 2017, partially offset by a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$51 12.5 $138 11.1
In the third quarter 2018, interest expense, net of amounts capitalized was $458 million compared to $407 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $1.4 billion compared to $1.2 billion in the corresponding period in 2017. These increases were primarily due to an increase in variable interest rates and average outstanding debt at the parent company and a $33 million net reduction in the third quarter 2017 following a settlement with the IRS related to research and experimental deductions at Mississippi Power, partially offset by a decrease in average outstanding debt at Georgia Power. The year-to-date 2018 increase was also due to new debt issuances and short-term debt at Southern Company Gas and a reduction in AFUDC debt of $24 million related to the Kemper IGCC project suspension in June 2017 at Mississippi Power.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(8) (12.3) $30 18.2
In the third quarter 2018, other income (expense), net was $57 million compared to $65 million for the corresponding period in 2017. The decrease was primarily due to a reduction of gains from the settlement of contractor litigation claims at Southern Company Gas, partially offset by a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests.
For year-to-date 2018, other income (expense), net was $195 million compared to $165 million for the corresponding period in 2017. The increase was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests, partially offset by a reduction of gains from the settlement of contractor litigation claims at Southern Company Gas.
See Note (B) to the Condensed Financial Statements herein under "General Litigation Matters – Mississippi Power" and "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" and Note (J) to the Condensed Financial Statements herein under "Southern Power – Development Projects" for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$33 5.6 $281 88.6
In the third quarter 2018, income taxes were $623 million compared to $590 million for the corresponding period in 2017. The increase was primarily due to tax expense related to the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas and the recognition of a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by 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 and a decrease in pre-tax earnings (excluding the gains on the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas).
For year-to-date 2018, income taxes were $598 million compared to $317 million for the corresponding period in 2017. The increase was primarily due to an increase in pre-tax earnings, primarily resulting from charges recorded in 2017 related to the Kemper IGCC at Mississippi Power partially offset by the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power recognized in the second quarter 2018, and tax expense related to the Southern Company Gas Dispositions. This increase was partially offset by 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 and the net state income tax benefits arising from the reorganizations of certain of Southern Power's legal entities.
See Note (H) to the Condensed Financial Statements herein for additional information.
Dividends on Preferred and Preference Stock of Subsidiaries
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(6) (60.0) $(20) (62.5)
In the third quarter 2018, dividends on preferred and preference stock of subsidiaries was $4 million compared to $10 million for the corresponding period in 2017. For year-to-date 2018, dividends on preferred and preference stock of subsidiaries was $12 million compared to $32 million for the corresponding period in 2017. These decreases were primarily due to the 2017 redemptions of all outstanding shares of preferred and preference stock at Georgia Power.
See Note 6 the financial statements of Southern Company under "Redeemable Preferred Stock of Subsidiaries" in Item 8 of the Form 10-K for additional information. Also see FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for information on Mississippi Power's redemption of all of its outstanding preferred stock subsequent to September 30, 2018.
Net Income Attributable to Noncontrolling Interests
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$24 80.0 $23 47.9
Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
In the third quarter 2018, net income attributable to noncontrolling interests was $54 million compared to $30 million for the corresponding period in 2017. The increase was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to the sale of a 33% equity interest in SPSH in 2018, the company holding substantially all of Southern Power's solar facilities.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2018, net income attributable to noncontrolling interests was $71 million compared to $48 million for the corresponding period in 2017. The increase was primarily due to $21 million of net income allocations due to the sale of a 33% equity interest in SPSH in 2018 and $14 million of other income allocations attributable to a joint-development wind project, partially offset by a reduction of $10 million of net income allocations to other partnership interests, primarily due to the tax equity partnership for Gaskell West 1.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain constructive regulatory environments that 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 and the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.
Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
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 $1.3 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 expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

their affiliates, and (iii) other customary closing conditions. 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 $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. 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, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth 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, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.
The after-tax impacts of the 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. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of these 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.
Environmental Matters
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. 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 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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.
On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. The Southern Company system is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategies due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
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 were based on information from feasibility studies performed on ash ponds in use
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
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 and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. 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
See Note 1 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.
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.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's ARO liability. The ultimate outcome of these studies cannot be determined at this time.
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 the Clean Power Plan and domestic GHG policies.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, the Southern Company system has ownership interests in 44 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to the Southern Company system is currently unknown and will depend on changes
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
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 – 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 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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's results of operations. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.
The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.
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 September 30, 2018, Alabama Power's equity ratio was approximately 47%. 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 has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
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 September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company under "Federal Tax Reform Legislation" in Item 8 of the Form 10-K for additional information.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 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. At September 30, 2018, Georgia Power's related regulatory liability balance totaled $655 million. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. 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.
Storm Damage Recovery
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.
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.
Storm Damage Cost Recovery
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
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 provided 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 September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
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 became effective with 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 certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through a separate Mississippi Power cost rider. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation 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 is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $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 45% at September 30, 2018) to 50% by December 31, 2018. 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 are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.
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 September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 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 $20 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 $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.
Construction Program
See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the construction program. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements under "Southern Power" herein.
Kemper IGCC
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net Income

of the gasifier portion of the Kemper IGCC. Mississippi Power expects
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$95 8.9 $1,601 N/M
N/M - Not meaningful
Consolidated net income attributable to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCCSouthern Company was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8$1.2 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million1.14 per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax)share) for the third quarter 20172018 compared to $1.1 billion ($1.07 per share) for the corresponding period in 2017. The increase was primarily due to lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017. These increases were partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and an increase in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $1.9 billion ($1.92 per share) for year-to-date 2018 compared to $347 million ($0.35 per share) for the corresponding period in 2017. The increase was primarily due to charges of $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, sincein 2017 related to the Kemper IGCC project started,at Mississippi Power, has incurred charges of $6.0partially offset by a $1.1 billion ($4.00.8 billion after tax) through September 30, 2017.
Mississippi Power reachedcharge in the second quarter 2018 for an estimated probable loss on Georgia Power's construction of Plant Vogtle Units 3 and filed4. Also contributing to the increase were lower federal income tax expense as a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditionsresult of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers,Tax Reform Legislation and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modifiedhigher retail electric revenues due to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would,colder weather in the future, file a reserve margin plan withfirst quarter 2018 and warmer weather in the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5,second and third quarters 2018 compared to the corresponding periods in 2017, noting Mississippipartially offset by reductions in retail revenues related to Tax Reform Legislation impacts and impairment charges at Southern Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission andSouthern Company Gas, primarily related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle"dispositions described in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B)(J) to the Condensed Financial Statements under "herein.
Retail Electric Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(10) (0.2) $127 1.1
In the third quarter 2018, retail electric revenues were $4.61 billion compared to $4.62 billion for the corresponding period in 2017. For year-to-date 2018, retail electric revenues were $11.9 billion compared to $11.8 billion for the corresponding period in 2017.
Details of the changes in retail electric revenues were as follows:
  Third Quarter 2018 Year-to-Date 2018
  (in millions) (% change) (in millions) (% change)
Retail electric – prior year $4,615
   $11,786
  
Estimated change resulting from –        
Rates and pricing (198) (4.2) (444) (3.8)
Sales growth 43
 0.9
 65
 0.6
Weather 80
 1.7
 297
 2.5
Fuel and other cost recovery 65
 1.4
 209
 1.8
Retail electric – current year $4,605
 (0.2)% $11,913
 1.1 %
Integrated Coal Gasification Combined Cycle" herein.Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as regulatory liabilities for future
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Nuclear Construction
On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuantcustomer bill credits related to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligationTax Reform Legislation and decreases in revenues recognized under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of whichNCCR tariff at Georgia Power's proportionate share is approximately $1.7 billion,Power. The year-to-date 2018 decrease was partially offset by higher contributions from variable demand-driven pricing from commercial and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. On October 2, 2017,industrial customers at Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.Power.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 27, 2017, the Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
On September 28, 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. 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. See Note 63 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings""Regulatory Matters – Alabama Power," " – Georgia Power – Rate Plans," and " – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (E)(B) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information,information.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. In the third quarter and year-to-date 2018, weather-adjusted residential KWH sales increased 1.2% and 0.8%, respectively, and weather-adjusted commercial KWH sales increased 0.8% and 0.6%, respectively, primarily due to customer growth. Industrial KWH sales increased 2.4% and 1.9% in the third quarter and year-to-date 2018, respectively, primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, partially offset by decreased sales in the chemicals and paper sectors, primarily due to customer maintenance outages and on-site cogeneration.
Fuel and other cost recovery revenues increased $65 million and $209 million in the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to higher energy sales resulting from colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including applicable covenants, eventsthe energy component of default, mandatory prepayment events,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
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(25) (3.5) $56 3.0
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to borrowing.produce the energy.
An inability or other failure by ToshibaIn the third quarter 2018, wholesale electric revenues were $693 million compared to perform its obligations$718 million for the corresponding period in 2017. This decrease was related to a $20 million decrease in energy revenues and a $5 million decrease in capacity revenues. The decrease in energy revenues is primarily related to a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the Guarantee SettlementShared Services Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(SSA) between Mississippi Power and Cooperative Energy. These decreases were partially offset by an increase in revenues at Southern Power from new natural gas PPAs from existing facilities, an increase in sales from renewable facilities, and an increase in fuel costs that are contractually recovered through PPAs.
For year-to-date 2018, wholesale electric revenues were $1.92 billion compared to $1.87 billion for the corresponding period in 2017. This increase was related to a $70 million increase in energy revenues, partially offset by a $14 million decrease in capacity revenues. The increase in energy revenues primarily related to Southern Power included revenues from new natural gas PPAs from existing facilities, an increase in fuel costs that are contractually recovered through PPAs, and an increase in sales from renewable facilities. These increases were partially offset by a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the SSA between Mississippi Power and Cooperative Energy.
Natural Gas Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(40) (7.5) $60 2.2
In the third quarter 2018, natural gas revenues were $492 million compared to $532 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues were $2.8 billion compared to $2.7 billion for the corresponding period in 2017.
Details of the changes in natural gas revenues were as follows:
 Third Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Natural gas revenues – prior year$532
   $2,746
  
Estimated change resulting from –       
Infrastructure replacement programs and base rate changes—
 —
 53
 1.9
Gas costs and other cost recovery(16) (3.0) (24) (0.9)
Weather1
 0.2
 17
 0.6
Wholesale gas services17
 3.2
 46
 1.7
Dispositions(*)
(43) (8.1) (30) (1.1)
Other1
 0.2
 (2) —
Natural gas revenues – current year$492
 (7.5)% $2,806
 2.2 %
(*)
Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased for year-to-date 2018 due to continued investments recovered through infrastructure replacement programs and 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 in the third quarter 2018 decreased primarily due to reduced natural gas prices during the third quarter 2018 compared to the corresponding period in 2017 and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues attributable to gas costs and other cost recovery for year-to-date 2018 decreased due to reduced natural gas prices during 2018 compared to the corresponding period in 2017, partially offset by increased volumes of natural gas sold in 2018 as a result of colder weather, as determined by Heating Degree Days.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and Southern Company Gas' gas marketing services customers in Georgia and Illinois.
Revenues attributable to Southern Company Gas' wholesale gas services business increased primarily due to increased commercial activity, partially offset by derivative losses.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations.
See Note (B) to the Condensed Financial Statements herein under "Regulatory Matters – Southern Company Gas" for additional information.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$31 18.5 $513 103.8
In the third quarter 2018, other revenues were $199 million compared to $168 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $1.0 billion compared to $494 million for the corresponding period in 2017. These increases were related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure, partially offset by a decrease in revenues resulting from the sale of Pivotal Home Solutions on June 4, 2018 at Southern Company Gas. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico. Additionally, these increases reflect $21 million and $40 million of revenues in the third quarter and year-to-date 2018, respectively, from unregulated sales of products and services that were reclassified to 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 the adoption of ASC 606.
Fuel and Purchased Power Expenses
 Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
 (change in millions) (% change) (change in millions) (% change)
Fuel$25
 1.9 $142
 4.2
Purchased power1
 0.4 114
 17.6
Total fuel and purchased power expenses$26
   $256
  
In the third quarter 2018, total fuel and purchased power expenses were $1.6 billion compared to $1.5 billion for the corresponding period in 2017. The increase was primarily the result of a $68 million increase in the volume of KWHs generated and purchased, partially offset by a $42 million decrease in the average cost of fuel and purchased power.
For year-to-date 2018, total fuel and purchased power expenses were $4.3 billion compared to $4.0 billion for the corresponding period in 2017. The increase was primarily the result of a $300 million increase in the volume of KWHs generated and purchased, partially offset by a $74 million net decrease in the average cost of fuel and purchased power. In addition, fuel expense increased $30 million for 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" and " – Alabama Power – Accounting Order" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
Details of the Southern Company system's generation and purchased power were as follows:
 Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in billions of KWHs)
56 55 153 147
Total purchased power (in billions of KWHs)
6 6 16 14
Sources of generation (percent) —
       
Gas47 47 46 46
Coal32 31 30 30
Nuclear14 15 15 16
Hydro2 2 3 2
Other5 5 6 6
Cost of fuel, generated (in cents per net KWH)(a) —
       
Gas2.78 2.92 2.79 2.93
Coal2.75 2.75 2.79 2.82
Nuclear0.81 0.80 0.80 0.80
Average cost of fuel, generated (in cents per net KWH)(a)
2.47 2.52 2.47 2.51
Average cost of purchased power (in cents per net KWH)(b)
5.32 5.36 5.52 5.32
(a)For year-to-date 2018, cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.
(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2018, fuel expense was $1.31 billion compared to $1.29 billion for the corresponding period in 2017. The increase was primarily due to a 7.5% increase in the volume of KWHs generated by natural gas and a 1.3% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated.
For year-to-date 2018, fuel expense was $3.5 billion compared to $3.4 billion for the corresponding period in 2017. The increase was primarily due to a 9.3% increase in the volume of KWHs generated by natural gas and a 4.1% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated and a 1.1% decrease in the average cost of coal per KWH generated.
Purchased Power
For year-to-date 2018, purchased power expense was $760 million compared to $646 million for the corresponding period in 2017. The increase was primarily due to a 10.5% increase in the volume of KWHs purchased and a 3.8% increase in the average cost per KWH purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Natural Gas
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(30) (22.4) $(32) (2.9)
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 75% and 83% of total cost of natural gas for the third quarter and year-to-date 2018, respectively.
In the third quarter 2018, cost of natural gas was $104 million compared to $134 million for the corresponding period in 2017. The decrease reflects $14 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in the third quarter 2018 as a result of fewer gas distribution customers, and a 3.2% decrease in natural gas prices during the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, cost of natural gas was $1.05 billion compared to $1.09 billion for the corresponding period in 2017. The decrease reflects $8 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in 2018 as a result of fewer gas distribution customers, as well as an 8.4% decrease in natural gas prices during 2018, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather compared to the corresponding period in 2017.
Cost of Other Sales
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$30 33.3 $395 134.8
In the third quarter 2018, cost of other sales was $120 million compared to $90 million for the corresponding period in 2017. For year-to-date 2018, cost of other sales was $688 million compared to $293 million for the corresponding period in 2017. These increases were related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico.
Other Operations and Maintenance Expenses
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$63 4.7 $117 2.9
In the third quarter 2018, other operations and maintenance expenses were $1.4 billion compared to $1.3 billion for the corresponding period in 2017. The increase was primarily due to a $22 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $21 million of disposition-related costs at Southern Company Gas. The increase also reflects $21 million of expenses from unregulated sales of products and services that were reclassified to 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.
For year-to-date 2018, other operations and maintenance expenses were $4.2 billion compared to $4.1 billion for the corresponding period in 2017. The increase was primarily due to a $60 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $29 million of disposition-related costs at
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company Gas. The increase also reflects $51 million of expenses from unregulated sales of products and services that were reclassified to 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. These increases were partially offset by a $32.5 million charge in the first quarter 2017 related to the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the settlement of Gulf Power's 2017 rate case. 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.
See Note (A) to the Condensed Financial Statements herein for additional information regarding the adoption of ASC 606.
Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$20 2.6 $102 4.6
In the third quarter 2018, depreciation and amortization was $787 million compared to $767 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $2.3 billion compared to $2.2 billion for the corresponding period in 2017. These increases primarily reflect increases of $18 million and $76 million for the third quarter and year-to-date 2018, respectively, related to additional plant in service. Additionally, the year-to-date 2018 increase was due to $34 million in depreciation credits recognized in 2017, 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
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$16 5.3 $49 5.2
In the third quarter 2018, taxes other than income taxes were $319 million compared to $303 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $990 million compared to $941 million for the corresponding period in 2017. These increases were primarily due to increased property taxes at the traditional electric operating companies and investment capital taxes at Southern Company Gas. Also contributing to the year-to-date 2018 increase was an increase in municipal franchise fees primarily related to higher retail revenues at Georgia Power and an increase in revenue tax expenses as a result of higher revenues at Southern Company Gas.
Estimated Loss on Plants Under Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(33) (97.1) $(2,050) (65.0)
In the third quarter 2018, estimated loss on plants under construction was $1 million compared to $34 million for the corresponding period in 2017. For year-to-date 2018, estimated loss on plants under construction was $1.1 billion compared to $3.2 billion for the corresponding period in 2017. The third quarter 2018 decrease was primarily due to lower costs associated with abandonment and related closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power. The year-to-date 2018 decrease was primarily due to revisions to the estimated construction costs for, and subsequent suspension in June 2017 of, the Kemper IGCC at Mississippi
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Power, partially offset by charges in 2018 related to Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4.
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.
Gain on Dispositions, Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$353 N/M $298 N/M
N/M - Not meaningful
In the third quarter and year-to-date 2018, a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax), respectively, were recorded related to the Southern Company Gas Dispositions. The year-to-date 2018 increase in gain on dispositions, net was partially offset by a $19 million decrease in gains from sales of integrated transmission system assets at Georgia Power. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information regarding related income taxes which substantially offset the gains for the Southern Company Gas Dispositions.
Impairment Charges
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$36 N/M $197 N/M
N/M - Not meaningful
Southern Power recorded a $36 million asset impairment charge in the third quarter 2018 on wind turbine equipment held for development projects and a $119 million asset impairment charge in the second quarter 2018 in contemplation of the sale of its Florida plants. Additionally, Southern Company Gas recorded a goodwill impairment charge of $42 million during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions.
See Notes (A) and (J) to the Condensed Financial Statements herein under "Goodwill and Other Intangible Assets" and under "Southern Power – Sale of Florida Plants" and "Southern Company Gas," respectively, for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$18 100.0 $(34) (25.6)
In the third quarter 2018, AFUDC equity was $36 million compared to $18 million in the corresponding period in 2017. The increase was primarily due to a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.
For year-to-date 2018, AFUDC equity was $99 million compared to $133 million in the corresponding period in 2017. The decrease primarily resulted from Mississippi Power's suspension of the Kemper IGCC construction in June 2017, partially offset by a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$51 12.5 $138 11.1
In the third quarter 2018, interest expense, net of amounts capitalized was $458 million compared to $407 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $1.4 billion compared to $1.2 billion in the corresponding period in 2017. These increases were primarily due to an increase in variable interest rates and average outstanding debt at the parent company and a $33 million net reduction in the third quarter 2017 following a settlement with the IRS related to research and experimental deductions at Mississippi Power, partially offset by a decrease in average outstanding debt at Georgia Power. The year-to-date 2018 increase was also due to new debt issuances and short-term debt at Southern Company Gas and a reduction in AFUDC debt of $24 million related to the Kemper IGCC project suspension in June 2017 at Mississippi Power.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(8) (12.3) $30 18.2
In the third quarter 2018, other income (expense), net was $57 million compared to $65 million for the corresponding period in 2017. The decrease was primarily due to a reduction of gains from the settlement of contractor litigation claims at Southern Company Gas, partially offset by a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests.
For year-to-date 2018, other income (expense), net was $195 million compared to $165 million for the corresponding period in 2017. The increase was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests, partially offset by a reduction of gains from the settlement of contractor litigation claims at Southern Company Gas.
See Note (B) to the Condensed Financial Statements herein under "General Litigation Matters – Mississippi Power" and "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" and Note (J) to the Condensed Financial Statements herein under "Southern Power – Development Projects" for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$33 5.6 $281 88.6
In the third quarter 2018, income taxes were $623 million compared to $590 million for the corresponding period in 2017. The increase was primarily due to tax expense related to the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas and the recognition of a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by 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 and a decrease in pre-tax earnings (excluding the gains on the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas).
For year-to-date 2018, income taxes were $598 million compared to $317 million for the corresponding period in 2017. The increase was primarily due to an increase in pre-tax earnings, primarily resulting from charges recorded in 2017 related to the Kemper IGCC at Mississippi Power partially offset by the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power recognized in the second quarter 2018, and tax expense related to the Southern Company Gas Dispositions. This increase was partially offset by 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 and the net state income tax benefits arising from the reorganizations of certain of Southern Power's legal entities.
See Note (H) to the Condensed Financial Statements herein for additional information.
Dividends on Preferred and Preference Stock of Subsidiaries
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(6) (60.0) $(20) (62.5)
In the third quarter 2018, dividends on preferred and preference stock of subsidiaries was $4 million compared to $10 million for the corresponding period in 2017. For year-to-date 2018, dividends on preferred and preference stock of subsidiaries was $12 million compared to $32 million for the corresponding period in 2017. These decreases were primarily due to the 2017 redemptions of all outstanding shares of preferred and preference stock at Georgia Power.
See Note 6 the financial statements of Southern Company under "Redeemable Preferred Stock of Subsidiaries" in Item 8 of the Form 10-K for additional information. Also see FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for information on Mississippi Power's redemption of all of its outstanding preferred stock subsequent to September 30, 2018.
Net Income Attributable to Noncontrolling Interests
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$24 80.0 $23 47.9
Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
In the third quarter 2018, net income attributable to noncontrolling interests was $54 million compared to $30 million for the corresponding period in 2017. The increase was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to the sale of a 33% equity interest in SPSH in 2018, the company holding substantially all of Southern Power's solar facilities.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2018, net income attributable to noncontrolling interests was $71 million compared to $48 million for the corresponding period in 2017. The increase was primarily due to $21 million of net income allocations due to the sale of a 33% equity interest in SPSH in 2018 and $14 million of other income allocations attributable to a joint-development wind project, partially offset by a reduction of $10 million of net income allocations to other partnership interests, primarily due to the tax equity partnership for Gaskell West 1.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain constructive regulatory environments that 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 and the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.
Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
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 $1.3 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 expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

their affiliates, and (iii) other customary closing conditions. 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 $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. 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, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth 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, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.
The after-tax impacts of the 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. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of these 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.
Environmental Matters
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. 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 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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.
On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. The Southern Company system is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategies due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
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 were based on information from feasibility studies performed on ash ponds in use
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
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 and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. 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
See Note 1 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.
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.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's ARO liability. The ultimate outcome of these studies cannot be determined at this time.
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 the Clean Power Plan and domestic GHG policies.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, the Southern Company system has ownership interests in 44 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to the Southern Company system is currently unknown and will depend on changes
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
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 – 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 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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's results of operations. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.
The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.
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 September 30, 2018, Alabama Power's equity ratio was approximately 47%. 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 has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
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 September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company under "Federal Tax Reform Legislation" in Item 8 of the Form 10-K for additional information.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 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. At September 30, 2018, Georgia Power's related regulatory liability balance totaled $655 million. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. 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.
Storm Damage Recovery
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.
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.
Storm Damage Cost Recovery
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
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 provided 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 September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
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 became effective with 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 certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through a separate Mississippi Power cost rider. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation 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 is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $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 45% at September 30, 2018) to 50% by December 31, 2018. 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 are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.
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 September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 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 $20 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 $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-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.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(70) (6.1) $(1,904) (84.6)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$95 8.9 $1,601 N/M
N/M - Not meaningful
Consolidated net income attributable to Southern Company was $1.07$1.2 billion ($1.14 per share) for the third quarter 2018 compared to $1.1 billion ($1.07 per share) for the third quarter 2017 compared to $1.14 billion ($1.18 per share) for the corresponding period in 2016.2017. The decreaseincrease was primarily due to lower federal income tax expense as a decrease inresult of the Tax Reform Legislation and higher retail electric revenues due to milderwarmer weather and lower customer usage, a decrease in tax benefits at Southern Power, and an increasethe third quarter 2018 compared to the corresponding period in depreciation and amortization.2017. These changesincreases were partially offset by higherreductions in retail electric revenues resulting from increases in base ratesrelated to Tax Reform Legislation impacts and a decreasean increase in operations and maintenance expenses.
Consolidated net income attributable to Southern Company was $347 million$1.9 billion ($0.351.92 per share) for year-to-date 20172018 compared to $2.3 billion$347 million ($2.400.35 per share) for the corresponding period in 2016.2017. The decreaseincrease was primarily due to charges of $3.2 billion and $222 million for year-to-date($2.2 billion after tax) in 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was an increase of $299 million in net income from Southern Company Gas reflecting the nine-month period in 2017 compared to the three-month period following the Merger closing on July 1, 2016, higher retail electric revenues resulting from increases in base rates, and increases in renewable energy sales at Southern Power, partially offset by a decrease$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 increase were lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to mildercolder weather in the first quarter 2018 and lower customer usage, higher interest expense,warmer weather in the second and an increasethird quarters 2018 compared to the corresponding periods in depreciation2017, partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and amortization.
Seeimpairment charges at Southern Power and Southern Company Gas, primarily related to the dispositions described in Note (B)(J) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger.herein.
Retail Electric Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(193) (4.0) $(146) (1.2)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(10) (0.2) $127 1.1
In the third quarter 2017,2018, retail electric revenues were $4.6$4.61 billion compared to $4.8$4.62 billion for the corresponding period in 2016.2017. For year-to-date 2017,2018, retail electric revenues were $11.8$11.9 billion compared to $11.9$11.8 billion for the corresponding period in 2016.2017.
Details of the changes in retail electric revenues were as follows:
 Third Quarter 2017 Year-to-Date 2017 Third Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change) (in millions) (% change) (in millions) (% change)
Retail electric – prior year $4,808
   $11,932
   $4,615
   $11,786
  
Estimated change resulting from –                
Rates and pricing 138
 2.9
 338
 2.8
 (198) (4.2) (444) (3.8)
Sales decline (52) (1.1) (74) (0.6)
Sales growth 43
 0.9
 65
 0.6
Weather (162) (3.4) (351) (2.9) 80
 1.7
 297
 2.5
Fuel and other cost recovery (117) (2.4) (59) (0.5) 65
 1.4
 209
 1.8
Retail electric – current year $4,615
 (4.0)% $11,786
 (1.2)% $4,605
 (0.2)% $11,913
 1.1 %
Revenues associated with changes in rates and pricing increaseddecreased in the third quarter and year-to-date 20172018 when compared to the corresponding periods in 20162017 primarily due to a Rate RSE increase at Alabama Power effectiverevenues deferred as regulatory liabilities for future
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

January 1, 2017,customer bill credits related to the recovery of Plant Vogtle Units 3Tax Reform Legislation and 4 construction financing costsdecreases in revenues recognized under the NCCR tariff at Georgia Power,Power. The year-to-date 2018 decrease was partially offset by higher contributions from variable demand-driven pricing from commercial and an increase in retail base revenues effective July 2017 and in environmental cost recovery effective November 2016industrial customers at GulfGeorgia Power.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " – Georgia Power – Rate Plans," and " – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreasedincreased in the third quarter and year-to-date 2017 when2018 when compared to the corresponding periods in 2016. Weather-adjusted2017. In the third quarter and year-to-date 2018, weather-adjusted residential KWH sales decreased 2.0%increased 1.2% and 0.8%, respectively, and weather-adjusted commercial KWH sales increased 0.8% and 0.6%, respectively, primarily due to customer growth. Industrial KWH sales increased 2.4% and 1.9% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales decreased 0.5% and 1.1% in the third quarter and year-to-date 2017,2018, respectively, primarily in the paperprimary metals sector, largely due to strong domestic demand for steel and aluminum, partially offset by increaseddecreased sales in the primary metalschemicals and textile sectors. Despite a more stable dollarpaper sectors, primarily due to customer maintenance outages and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes.on-site cogeneration.
Fuel and other cost recovery revenues decreased $117increased $65 million and $59$209 million in the third quarter and year-to-date 2017,2018, respectively, when compared to the corresponding periods in 20162017 primarily due to lowerhigher energy sales resulting from mildercolder weather in the first quarter 2018 and lower coal prices.warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017. 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
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$105 17.1 $412 28.3
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(25) (3.5) $56 3.0
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, Southern Company'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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the third quarter 20172018,, wholesale electric revenues were $718$693 million compared to $613$718 million for the corresponding period in 2016.2017. This increasedecrease was primarily related to a $78$20 million increasedecrease in energy revenues and a $27$5 million increasedecrease in capacity revenues. For year-to-date 2017, wholesale electricThe decrease in energy revenues were $1.9 billion compared to $1.5 billion for the corresponding period in 2016. This increase wasis primarily related to a $354 million increasedecrease in energy revenues and a $58 million increase in capacity revenues. The increases in energy revenues primarily relate to Southern Power increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increases in capacity revenues primarily resulted from PPAs related to new natural gas facilities and additional customer capacity requirementssales at Southern Power.
Other Electric Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(13) (7.2) $(19) (3.6)
In the third quarter 2017, other electric revenues were $168 million compared to $181 million for the corresponding period in 2016. The decrease was primarily related to lower open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power and rate adjustments at Alabama Power and a decrease in solar application fee revenues at Georgia Power.
For year-to-date 2017, other electric revenues were $510 million compared to $529 million forrevenue under the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenues and a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions at Georgia Power.
Natural Gas Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$14 2.7 $2,228 N/M
N/M - Not meaningful
Natural gas revenues represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. In the third quarter 2017, natural gas revenues were $532 million compared to $518 million for the corresponding period in 2016. This increase is primarily due to infrastructure replacement programs and increases in base rate revenues at Southern Company Gas.
For year-to-date 2017, natural gas revenues were $2.7 billion compared to $518 million for the corresponding period in 2016. The increase reflects the inclusion of Southern Company Gas results for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$24 16.7 $213 75.8
In the third quarter 2017, other revenues were $168 million compared to $144 million for the corresponding period in 2016. For year-to-date 2017, other revenues were $494 million compared to $281 million for the correspondingShared Services Agreement
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(SSA) between Mississippi Power and Cooperative Energy. These decreases were partially offset by an increase in revenues at Southern Power from new natural gas PPAs from existing facilities, an increase in sales from renewable facilities, and an increase in fuel costs that are contractually recovered through PPAs.
For year-to-date 2018, wholesale electric revenues were $1.92 billion compared to $1.87 billion for the corresponding period in 2016.2017. This increase was related to a $70 million increase in energy revenues, partially offset by a $14 million decrease in capacity revenues. The increase in energy revenues primarily related to Southern Power included revenues from new natural gas PPAs from existing facilities, an increase in fuel costs that are contractually recovered through PPAs, and an increase in sales from renewable facilities. These increases were partially offset by a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the SSA between Mississippi Power and Cooperative Energy.
Natural Gas Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(40) (7.5) $60 2.2
In the third quarter 2018, natural gas revenues were $492 million compared to $532 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues were $2.8 billion compared to $2.7 billion for the corresponding period in 2017.
Details of the changes in natural gas revenues were as follows:
 Third Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Natural gas revenues – prior year$532
   $2,746
  
Estimated change resulting from –       
Infrastructure replacement programs and base rate changes—
 —
 53
 1.9
Gas costs and other cost recovery(16) (3.0) (24) (0.9)
Weather1
 0.2
 17
 0.6
Wholesale gas services17
 3.2
 46
 1.7
Dispositions(*)
(43) (8.1) (30) (1.1)
Other1
 0.2
 (2) —
Natural gas revenues – current year$492
 (7.5)% $2,806
 2.2 %
(*)
Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased for year-to-date 2018 due to continued investments recovered through infrastructure replacement programs and 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 in the third quarter 2018 decreased primarily due to reduced natural gas prices during the third quarter 2018 compared to the corresponding period in 2017 and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues attributable to gas costs and other cost recovery for year-to-date 2018 decreased due to reduced natural gas prices during 2018 compared to the corresponding period in 2017, partially offset by increased volumes of natural gas sold in 2018 as a result of colder weather, as determined by Heating Degree Days.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and Southern Company Gas' gas marketing services customers in Georgia and Illinois.
Revenues attributable to Southern Company Gas' wholesale gas services business increased primarily due to increased commercial activity, partially offset by derivative losses.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations.
See Note (B) to the Condensed Financial Statements herein under "Regulatory Matters – Southern Company Gas" for additional information.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$31 18.5 $513 103.8
In the third quarter 2018, other revenues were $199 million compared to $168 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $1.0 billion compared to $494 million for the corresponding period in 2017. These increases were related to an increase in sales of $5products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure, partially offset by a decrease in revenues resulting from the sale of Pivotal Home Solutions on June 4, 2018 at Southern Company Gas. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico. Additionally, these increases reflect $21 million and $135$40 million forof revenues in the third quarter and year-to-date 2017,2018, respectively, from products and services at PowerSecure, which was acquired on May 9, 2016, and $8 million and $70 million for the third quarter and year-to-date 2017, respectively, of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, revenues from certain non-regulatedunregulated sales of products and services atthat were reclassified to other revenues as a result of the traditional electric operating companies increased $5 million and $13 million for the third quarter and year-to-date 2017, respectively, primarily due to additional third-party infrastructure services.
adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (I)(A) to the Condensed Financial Statements under "Southern Company" herein for additional information onregarding the Merger and the acquisitionadoption of PowerSecure.ASC 606.
Fuel and Purchased Power Expenses
Third Quarter 2017
vs.
Third Quarter 2016		 Year-to-Date 2017
vs.
Year-to-Date 2016		Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$(115) (8.2) $38
 1.1$25
 1.9 $142
 4.2
Purchased power29
 12.8 65
 11.21
 0.4 114
 17.6
Total fuel and purchased power expenses$(86) $103
 $26
 $256
 
In the third quarter 20172018, total fuel and purchased power expenses were $1.5$1.6 billion compared to $1.6$1.5 billion for the corresponding period in 2016.2017. The decreaseincrease was primarily the result of a $104$68 million net decreaseincrease in the volume of KWHs generated and purchased, partially offset by an $18a $42 million net increasedecrease in the average cost of fuel and purchased power primarily due to higher natural gas prices.power.
For year-to-date 2017,2018, total fuel and purchased power expenses were $4.0$4.3 billion compared to $3.9$4.0 billion for the corresponding period in 2016.2017. The increase was primarily the result of a $277$300 million increase in the volume of KWHs generated and purchased, partially offset by a $74 million net decrease in the average cost of fuel and purchased power primarily duepower. In addition, fuel expense increased $30 million for year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to higher natural gas prices, partially offset by a $174 million decrease in the volume of KWHs generated and purchased.under recovered fuel costs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost RecoveryRecovery" and " – Alabama Power – Accounting Order" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the Southern Company system's generation and purchased power were as follows:
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in billions of KWHs)
54 56 147 14556 55 153 147
Total purchased power (in billions of KWHs)
6 6 14 156 6 16 14
Sources of generation (percent) —
      
Gas47 47 46 46
Coal31 38 30 3332 31 30 30
Nuclear15 15 16 1614 15 15 16
Gas47 44 46 46
Hydro2 1 2 32 2 3 2
Other5 2 6 25 5 6 6
Cost of fuel, generated (in cents per net KWH) —
   
Cost of fuel, generated (in cents per net KWH)(a) —
   
Gas2.78 2.92 2.79 2.93
Coal2.82 2.97 2.82 3.102.75 2.75 2.79 2.82
Nuclear0.80 0.81 0.80 0.820.81 0.80 0.80 0.80
Gas2.92 2.74 2.93 2.40
Average cost of fuel, generated (in cents per net KWH)(a)
2.54 2.54 2.51 2.382.47 2.52 2.47 2.51
Average cost of purchased power (in cents per net KWH)(*)
4.96 4.98 5.32 4.75
Average cost of purchased power (in cents per net KWH)(b)
5.32 5.36 5.52 5.32
(*)(a)For year-to-date 2018, cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.
(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 20172018, fuel expense was $1.3$1.31 billion compared to $1.4$1.29 billion for the corresponding period in 2016.2017. The decreaseincrease was primarily due to a 21.4% decrease7.5% increase in the volume of KWHs generated by natural gas and a 1.3% increase in the volume of KWHs generated by coal, andpartially offset by a 5.1%4.8% decrease in the average cost of coalnatural gas per KWH generated.
For year-to-date 2018, fuel expense was $3.5 billion compared to $3.4 billion for the corresponding period in 2017. The increase was primarily due to a 9.3% increase in the volume of KWHs generated by natural gas and a 4.1% increase in the volume of KWHs generated by coal, partially offset by a 6.6% increase4.8% decrease in the average cost of natural gas per KWH generated and a 1.2% increase in the volume of KWHs generated by natural gas.
For year-to-date 2017, fuel expense was $3.4 billion compared to $3.3 billion for the corresponding period in 2016. The increase was primarily due to a 22.1% increase in the average cost of natural gas per KWH generated, partially offset by a 9.0%1.1% decrease in the average cost of coal per KWH generated, a 7.4% decrease in the volume of KWHs generated by coal, and a 3.7% decrease in the volume of KWHs generated by natural gas.generated.
Purchased Power
In the third quarter 2017,For year-to-date 2018, purchased power expense was $256$760 million compared to $227$646 million for the corresponding period in 2016.2017. The increase was primarily due to a 10.1%10.5% increase in the volume of KWHs purchased partially offset byand a 0.4% decrease in the average cost per KWH purchased.
For year-to-date 2017, purchased power expense was $646 million compared to $581 million for the corresponding period in 2016. The increase was primarily due to a 12.0%3.8% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 1.3% decrease in the volume of KWHs purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Natural Gas
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$1 0.8 $952 N/M
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(30) (22.4) $(32) (2.9)
N/M - Not meaningful
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas represents the cost of natural gas sold byat the natural gas distribution utilities represented 75% and certain non-regulated operations83% of Southern Company Gas. total cost of natural gas for the third quarter and year-to-date 2018, respectively.
In the third quarter 2017,2018, cost of natural gas was $134$104 million compared to $133$134 million for the corresponding period in 2016. 2017. The decrease reflects $14 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in the third quarter 2018 as a result of fewer gas distribution customers, and a 3.2% decrease in natural gas prices during the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2017,2018, cost of natural gas was $1.1$1.05 billion compared to $133 million$1.09 billion for the corresponding period in 2016.2017. The year-to-date increasedecrease reflects $8 million related to the inclusion of Southern Company Gas results forDispositions, which resulted in a decrease in the nine-month periodvolume of natural gas sold in 20172018 as a result of fewer gas distribution customers, as well as an 8.4% decrease in natural gas prices during 2018, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather compared to the three-monthcorresponding period subsequent to the Merger closing on July 1, 2016.in 2017.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Cost of Other Sales
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$6 7.1 $132 82.0
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$30 33.3 $395 134.8
In the third quarter 20172018, cost of other sales was $90$120 million compared to $84$90 million for the corresponding period in 2016.2017. For year-to-date 2017,2018, cost of other sales was $293$688 million compared to $161$293 million for the corresponding period in 2016. The year-to-date2017. These increases were related to an increase primarily reflects costs related toin sales of products and services by PowerSecure, whichfrom additional customer contracts in distributed generation and utility infrastructure at PowerSecure. The year-to-date 2018 increase was acquired on May 9, 2016, and costsprimarily related to gas marketing products andstorm restoration services at Southern Company Gas following the Merger closing on July 1, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information.in Puerto Rico.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(124) (8.8) $302 8.4
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$63 4.7 $117 2.9
In the third quarter 20172018, other operations and maintenance expenses were $1.3$1.4 billion compared to $1.4$1.3 billion for the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $37 million in maintenance costs, $9 million in customer accounts, service, and sales costs, and $8 million in other employee compensation and benefits. Other factors include a $40 million decrease in acquisition-related expenses and a $31 million decrease in employee compensation and benefits including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $3.9 billion compared to $3.6 billion for the corresponding period in 2016.2017. The increase was primarily due to increasesa $22 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $21 million of $420disposition-related costs at Southern Company Gas. The increase also reflects $21 million of expenses from unregulated sales of products and $32 million inservices that were reclassified to other operations and maintenance expenses as a result of the inclusionadoption of Southern Company GasASC 606. In prior periods, these expenses were included in other income (expense), net.
For year-to-date 2018, other operations and PowerSecure resultsmaintenance expenses were $4.2 billion compared to $4.1 billion for the nine-monthcorresponding period in 2017, respectively,2017. The increase was primarily due to a $48$60 million increase associated with new solar, wind,in electric transmission and gas facilities at Southern Power, and $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement). These increases were partially offsetdistribution costs, primarily due to cost containmentadditional line maintenance, and modernization activities implemented$29 million of disposition-related costs at Georgia Power in the third quarter 2016 that contributed to decreases of $79 million in maintenance costs and $34 million in other employee compensation and benefits. Other factors
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

include a $32Southern Company Gas. The increase also reflects $51 million decrease in acquisition-relatedof expenses a $25 million decrease in customer accounts, service, and sales costs primarily at Georgia Power, a $19 million increase in gains from unregulated sales of integrated transmission system assets at Georgia Power,products and a $16 million decrease in scheduled outageservices that were reclassified to other operations and maintenance costs at generation facilities.
See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.
Depreciation and Amortization
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$72 10.4 $431 23.9
In the third quarter 2017, depreciation and amortization was $767 million compared to $695 million for the corresponding period in 2016. The increase is primarily related to additional plant in service at the traditional electric operating companies, Southern Power, and Southern Company Gas.
For year-to-date 2017, depreciation and amortization was $2.2 billion compared to $1.8 billion for the corresponding period in 2016. The increase reflects $254 millionexpenses as a result of the inclusionadoption of Southern Company Gas for the nine-month periodASC 606. In prior periods, these expenses were included in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects $170 million related to additional plant in service at the traditional electric operating companies and Southern Power. The increase wasother income (expense), net. These increases were partially offset by a $34$32.5 million increasecharge in the reductions in depreciation authorized infirst quarter 2017 related to the write-down of Gulf Power's 2013ownership of Plant Scherer Unit 3 in accordance with the settlement of Gulf Power's 2017 rate case settlement approved by the Florida PSC as compared to the corresponding period in 2016.
case. 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 and Notes (B) and (I)for additional information.
See Note (A) to the Condensed Financial Statements herein for additional information regarding the adoption of ASC 606.
Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$20 2.6 $102 4.6
In the third quarter 2018, depreciation and amortization was $787 million compared to $767 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $2.3 billion compared to $2.2 billion for the corresponding period in 2017. These increases primarily reflect increases of $18 million and $76 million for the third quarter and year-to-date 2018, respectively, related to additional plant in service. Additionally, the year-to-date 2018 increase was due to $34 million in depreciation credits recognized in 2017, as authorized in Gulf Power's 2013 rate case settlement. See Note 3 to the financial statements of Southern Company under "Regulatory"Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Southern Company – Merger with Southern Company Gas," respectively, hereinCases" in Item 8 of the Form 10-K for additional information.
Taxes Other Than Income Taxes
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(6) (1.9) $120 14.6
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$16 5.3 $49 5.2
For year-to-date 2017,In the third quarter 2018, taxes other than income taxes were $941$319 million compared to $821$303 million for the corresponding period in 2016. The increase2017. For year-to-date 2018, taxes other than income taxes were $990 million compared to $941 million for the corresponding period in 2017. These increases were primarily reflectsdue to increased property taxes at the inclusion oftraditional electric operating companies and investment capital taxes at Southern Company Gas taxesGas. Also contributing to the year-to-date 2018 increase was an increase in municipal franchise fees primarily related to higher retail revenues at Georgia Power and an increase in revenue tax expenses as a result of higher revenues at Southern Company Gas.
Estimated Loss on Plants Under Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(33) (97.1) $(2,050) (65.0)
In the third quarter 2018, estimated loss on plants under construction was $1 million compared to $34 million for the nine-monthcorresponding period in 20172017. For year-to-date 2018, estimated loss on plants under construction was $1.1 billion compared to $3.2 billion for the three-monthcorresponding period subsequentin 2017. The third quarter 2018 decrease was primarily due to lower costs associated with abandonment and related closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power. The year-to-date 2018 decrease was primarily due to revisions to the Merger closing on July 1, 2016.
See Note (I) toestimated construction costs for, and subsequent suspension in June 2017 of, the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.Kemper IGCC at Mississippi
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Estimated Loss on Kemper IGCCPower, partially offset by charges in 2018 related to Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4.
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(54) (61.4) $2,933 N/M
N/M - Not meaningful
Estimated probable losses onSee Note 3 to the Kemper IGCCfinancial statements of $34 million and $3.2 billion were recorded at Mississippi PowerSouthern Company under "Kemper County Energy Facility" in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate dispositionItem 8 of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.
Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle"Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined CycleKemper County Energy Facility" and "Nuclear Construction" herein for additional information.
Gain on Dispositions, Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$353 N/M $298 N/M
N/M - Not meaningful
In the third quarter and year-to-date 2018, a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax), respectively, were recorded related to the Southern Company Gas Dispositions. The year-to-date 2018 increase in gain on dispositions, net was partially offset by a $19 million decrease in gains from sales of integrated transmission system assets at Georgia Power. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information regarding related income taxes which substantially offset the gains for the Southern Company Gas Dispositions.
Impairment Charges
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$36 N/M $197 N/M
N/M - Not meaningful
Southern Power recorded a $36 million asset impairment charge in the third quarter 2018 on wind turbine equipment held for development projects and a $119 million asset impairment charge in the second quarter 2018 in contemplation of the sale of its Florida plants. Additionally, Southern Company Gas recorded a goodwill impairment charge of $42 million during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions.
See Notes (A) and (J) to the Condensed Financial Statements herein under "Goodwill and Other Intangible Assets" and under "Southern Power – Sale of Florida Plants" and "Southern Company Gas," respectively, for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(34) (65.4) $(17) (11.3)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$18 100.0 $(34) (25.6)
In the third quarter 2017,2018, AFUDC equity was $18$36 million compared to $52$18 million in the corresponding period in 2016. 2017. The increase was primarily due to a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.
For year-to-date 2017,2018, AFUDC equity was $133$99 million compared to $150$133 million in the corresponding period in 2016. These decreases2017. The decrease primarily resulted from Mississippi Power's suspension of the Kemper IGCC projectconstruction in June 2017.
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle"2017, partially offset by a higher AFUDC rate resulting from a higher equity ratio and Note (B)lower short-term borrowings at Georgia Power and a higher AFUDC base related to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Earnings from Equity Method Investments
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$3 10.3 $72 N/M
N/M - Not meaningful
In the third quarter 2017, earnings from equity method investments were $32 million compared to $29 million in the corresponding period in 2016. For year-to-date 2017, earnings from equity method investments were $100 millionenvironmental and transmission projects at Alabama Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

compared to $28 million in the corresponding period in 2016. These increases were primarily related to Southern Company Gas' equity method investment in SNG in September 2016.
See Note 123 to the financial statements of Southern Company under "Southern Company – Investment in Southern Natural Gas""Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.10-K.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$33 8.8 $335 36.7
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$51 12.5 $138 11.1
In the third quarter 20172018, interest expense, net of amounts capitalized was $407$458 million compared to $374$407 million in the corresponding period in 2016. The increase2017. For year-to-date 2018, interest expense, net of amounts capitalized was $1.4 billion compared to $1.2 billion in the corresponding period in 2017. These increases were primarily due to an increase in variable interest rates and average outstanding long-term debt at the parent company and a $16$33 million decrease in interest capitalized, partially offset by a net reduction of $33 millionin the third quarter 2017 following Mississippi Power'sa settlement with the IRS related to research and experimental (R&E) deductions.
For year-to-date 2017, interest expense, net of amounts capitalized was $1.2 billion compared to $913 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $31 million decrease in interest capitalized,deductions at Mississippi Power, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS relateddecrease in average outstanding debt at Georgia Power. The year-to-date 2018 increase was also due to R&E deductions. In addition, year-to-date 2017 includes an additional $106 million reflecting the nine-month period of interest expense fornew debt issuances and short-term debt at Southern Company Gas comparedand a reduction in AFUDC debt of $24 million related to the three-month period subsequentKemper IGCC project suspension in June 2017 at Mississippi Power.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 6 to the Merger closing on July 1, 2016.
See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Section 174 Researchfinancial statements of Southern Company in Item 8 of the Form 10-K, and Experimental Deduction" and Notes (E) and (G)Note (F) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$19 N/M $68 N/M
N/M - Not meaningful
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(8) (12.3) $30 18.2
In the third quarter 20172018, other income (expense), net was $11$57 million compared to $(8)$65 million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net2017. The decrease was $2 million compared to $(66) million for the corresponding period in 2016. These changes were primarily due to $14 million and $16 milliona reduction of gains from the settlement of contractor litigation claims at Southern Company Gas, partially offset by a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the third quarterproject and fully offset within noncontrolling interests.
For year-to-date 2017, respectively,2018, other income (expense), net was $195 million compared to $165 million for the corresponding period in 2017. The increase was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and increases of $6 million and $10 million in customer contributions in aid of construction and contract service revenuea gain from a joint-development wind project at GeorgiaSouthern Power, which is attributable to Southern Power's partner in the third quarterproject and year-to-date 2017, respectively. Additionally, the year-to-date change reflects $30 million of expenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $36 million and $152 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the third quarter and year-to-date 2017, respectively, fully offset within noncontrolling interests, partially offset by an equal change ina reduction of gains onfrom the foreign currency hedges that were reclassified from accumulated OCI into earningssettlement of contractor litigation claims at Southern Power.Company Gas.
See Note (H)(B) to the Condensed Financial Statements herein under "General Litigation Matters – Mississippi Power" and "Foreign Currency DerivativesRegulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" and Note (J) to the Condensed Financial Statements herein under "Southern Power – Development Projects" for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$151 34.4 $(600) (65.4)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$33 5.6 $281 88.6
In the third quarter 20172018, income taxes were $590$623 million compared to $439$590 million for the corresponding period in 2016.2017. The increase was primarily due to tax expense related to the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas and the recognition of a $61 millionvaluation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by 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 and a decrease in income tax benefits from solar ITCs at Southern Power, a $23 million increase in deferred income tax expenses associated with new Statepre-tax earnings (excluding the gains on the sales of Illinois tax legislation and new tax apportionment factors at Southern CompanyElizabethtown Gas, Elkton Gas, and a $21 million decrease in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power.Florida City Gas).
For year-to-date 2017,2018, income taxes were $317$598 million compared to $917$317 million for the corresponding period in 2016.2017. The decreaseincrease was primarily due to $866 millionan increase in tax benefitspre-tax earnings, primarily resulting from charges recorded in 2017 related to estimated losses on the Kemper IGCC at Mississippi Power partially offset by a $226 million increase reflecting the nine-month period of income taxesestimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power recognized in the second quarter 2018, and tax expense related to the Southern Company Gas in 2017Dispositions. This increase was partially offset by 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 and the net state income tax benefits arising from the reorganizations of certain of Southern Power's legal entities.
See Note (H) to the Condensed Financial Statements herein for additional information.
Dividends on Preferred and Preference Stock of Subsidiaries
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(6) (60.0) $(20) (62.5)
In the third quarter 2018, dividends on preferred and preference stock of subsidiaries was $4 million compared to $10 million for the three-monthcorresponding period in 2017. For year-to-date 2018, dividends on preferred and preference stock of subsidiaries was $12 million compared to $32 million for the corresponding period in 2017. These decreases were primarily due to the 2017 redemptions of all outstanding shares of preferred and preference stock at Georgia Power.
See Note 6 the financial statements of Southern Company under "Redeemable Preferred Stock of Subsidiaries" in Item 8 of the Form 10-K for additional information. Also see FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for information on Mississippi Power's redemption of all of its outstanding preferred stock subsequent to the Merger closing on July 1, 2016 and a $44 million net decrease in tax benefits fromSeptember 30, 2018.
Net Income Attributable to Noncontrolling Interests
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$24 80.0 $23 47.9
Substantially all noncontrolling interests relate to renewable tax creditsprojects at Southern Power.
See Notes (B), (G), and (I)Note (J) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle," "Effective Tax Rate," and "Southern Company – Merger with Southern Company Gas," respectively,"Southern Power" herein for additional information.
In the third quarter 2018, net income attributable to noncontrolling interests was $54 million compared to $30 million for the corresponding period in 2017. The increase was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to the sale of a 33% equity interest in SPSH in 2018, the company holding substantially all of Southern Power's solar facilities.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2018, net income attributable to noncontrolling interests was $71 million compared to $48 million for the corresponding period in 2017. The increase was primarily due to $21 million of net income allocations due to the sale of a 33% equity interest in SPSH in 2018 and $14 million of other income allocations attributable to a joint-development wind project, partially offset by a reduction of $10 million of net income allocations to other partnership interests, primarily due to the tax equity partnership for Gaskell West 1.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a constructive regulatory environmentenvironments that allowsallow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Matters related to Plant Vogtle Units 3 and 4 construction and rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in current rates are also major factors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
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 highermore multi-family home construction.construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
On 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 consideringcurrently estimated at approximately $1.3 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 expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of upcertain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

their affiliates, and (iii) other customary closing conditions. See Note (J) to a one-third equity interest in its solar asset portfolio.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 October 15, 2017, a wholly-owned subsidiary ofJune 4, 2018, Southern Company Gas entered into agreementscompleted the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the salefinal working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. 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. Asbillion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of September 30, 2017,approximately $230 million and an after-tax gain of approximately $18 million, the net book valuecalculations of which are expected to be finalized in the fourth 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, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.
The after-tax impacts of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. TheSouthern Company Gas Dispositions included income tax expense on goodwill is not deductible for tax purposes and as a result,for which a deferred tax liability hashad not yet been providedrecorded previously. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for goodwill. Through the completion ofadditional information.
In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Company Gas intends to investPower's solar facilities, for an aggregate purchase price of approximately $0.1$1.2 billion. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in capital expenditurestax equity in SP Wind, which are required for ordinary business operations.owns a portfolio of eight operating wind facilities. The completion of each saletransaction is subject to Public Utility Commission of Texas approval and is expected to close by the satisfaction or waiverend of certain closing conditions, including, among others, (i)2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatoryAct and FERC and state commission approvals including the FERC, the Federal Communications Commission, the New Jersey BPU, and with respectis expected to close mid-2019. See Note (J) to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of these 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 and RISK FACTORS in Item 1A herein.10-K.
Environmental Matters
ComplianceThe Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs relatedassociated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to federal and statecomply with environmental statuteslaws 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental StatutesLaws and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's eight-hour ozone National Ambient Air Quality Standard (NAAQS).
On June 2, 2017, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the 2008 eight-hour ozone NAAQS.
On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extension and reinstated the original October 1, 2017 designation deadline. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes 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 effluent guidelinesrulemaking 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 final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these mattersany legal challenges and cannot be determined at this time.
Global Climate IssuesCoal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues"Environmental Laws and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information.information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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.
On March 28, 2017,October 15, 2018, the U.S. President signed an executive order directing agenciesCourt of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to review actionsregulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA will issue a series of rulemakings to reviewaddress this court action. The Southern Company system is evaluating the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generatingextent of potential impacts on legacy units and, if appropriate, take actionbut anticipates no significant impacts to suspend, revise, or rescind those rules. On October 16, 2017,its ongoing CCR strategies due to this mandate. The ultimate impact of these changes will not be known until the EPA published a proposed rulerulemaking and any legal challenges are finalized.
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters 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 (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the cavernsAROs related to the edge of the salt dome may be less than the required minimum and could resultCCR Rule. The revised cost estimates were based on information from feasibility studies performed on ash ponds in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itselfuse
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

representsat 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 the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
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 and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. 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
See Note 1 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.
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 20%. A potential early retirement$300 million. Amounts previously contributed to Alabama Power's external trust funds are currently projected to be adequate to meet the updated decommissioning obligations.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's ARO liability. The ultimate outcome of these studies cannot be determined at this time.
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 the Clean Power Plan and domestic GHG policies.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, the Southern Company system has ownership interests in 44 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this cavernrule to the Southern Company system is currently unknown and will depend on changes
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
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 upon severalon many external factors, including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with thesupportive national energy policies, low natural gas storage facility.prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceedingproceedings related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30,2014 and 2017 triennial updated market power analysis. Theanalyses.
On May 4, 2018, the FERC directedissued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power to show cause within 60 days whysatisfy the FERC's standards for market-based rate authority should not be revoked in certain areas adjacent torates. On May 9, 2018, the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expectmade the compliance filing required by the order. These proceedings are 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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to make a filing within the specified 60 days respondingbe material to the FERC's order.
Southern Company's results of operations. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Southern Company Gas" of Southern Company in Item 7 and Note 4 to the financial statements of Southern Company in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
On October 13, 2017, theThe Atlantic Coast Pipeline project received FERC approval.has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Renewables" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Southern Company system's renewables activity.
On May 16, 2017, the Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.
During the nine months ended September 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.
In 2015, the Florida PSC approved Gulf Power's three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.
Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020.
The ultimate outcome of these matters cannot be determined at this time.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and accounting orders. Thethe recovery balance of each regulatory clause for Alabama Power.
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is reportedto achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Southern Company in Note (B)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 Condensed Financial Statements herein.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 has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
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 September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company under "Federal Tax Reform Legislation" in Item 8 of the Form 10-K for additional information.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to thecertified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear"Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 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. At September 30, 2018, Georgia Power's related regulatory liability balance totaled $655 million. 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters –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. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power – Integrated Resource Plan"to cover the carrying costs of the incremental equity in 2018 and 2019.
Storm Damage Recovery
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 78 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Storm Damage Recoverystorm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operatingoperations and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017,2018, the total balance in Georgia Power's regulatory asset related to storm damage was $360$311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, required towhich is scheduled to be filed by July 1, 2019. As a resultThe ultimate outcome of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.matter cannot be determined at this time.
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 regardinginformation.
Storm Damage Cost Recovery
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's October 2016 requestservice territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), Gulf Power can petition the Florida PSC to increase retail base rates andseek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
As a continuation of the 2017 Gulf Power's ownership of Plant Scherer Unit 3.
On April 4, 2017,Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved the 2017 Rate Case Settlement Agreementa stipulation and settlement agreement among Gulf Power and three intervenors with respectaddressing 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 request to increase retailrevenues of $18.2 million from base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0and $15.6 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacityfrom environmental cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have an equity ratio of 52.5% for all retail regulatory purposes. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective Januaryrates implemented April 1, 2018 and will implement new depreciation rates effective January 1,also provided 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. The 2017 Rate Case Settlement Agreement also resultedThrough September 30, 2018, approximately $53 million of this refund has been reflected in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved ascustomer bills. As a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company GasGulf 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.
Natural Gas Cost Recovery
Southern Company GasAs 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. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has established natural gasdeferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery ratesrate.
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 relevant state regulatory agencies inMississippi PSC on August 7, 2018. Rates under 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 revenues or net income, but will affect cash flows.
Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate casePEP Settlement Agreement became effective with the Illinois Commission requesting a $208first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 million increase in annual base rate revenues.retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through a separate Mississippi Power cost rider. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset. The requested increaseMississippi PSC is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission iscurrently expected to rule on the requested increaseappropriate treatment for such costs in December 2017, afterconnection with Mississippi Power's next base rate case, which rate adjustments willis scheduled to be effective.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 is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $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 45% at September 30, 2018) to 50% by December 31, 2018. 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 are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.
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 September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 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 $20 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 $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. Following Mississippi Power's suspension of the Kemper IGCC construction, 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). In August 2017, Georgia Power filed its seventeenth VCM report with the Georgia PSC, in which it recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these and other related matters by February 6, 2018. 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.
For additional information, see Note See Notes 3 and 12 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and " – Southern Company Gas – Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle""Southern Power – Construction Projects in Progress," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters– Georgia Power – Nuclear Construction" and " – Southern Company Gas–Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" herein. Also see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I)(J) to the Condensed Financial Statements under "Southern Power" herein.herein for additional information.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Integrated Coal Gasification Combined Cycle
The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the MPUS, authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension,
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" herein.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear"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, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcytariff.
In 2008,2009, the Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and testPSC certified construction of Plant Vogtle Units 3 and 4. UnderIn 2012, the termsNRC issued the related combined construction and operating licenses, which allowed full construction of the Vogtle 3two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and 4 Agreement, the Vogtle Owners agreedrelated facilities to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share ofbegin. Until March 2017, construction on Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractorcontinued under the Vogtle 3 and 4 Agreement, which was 40% of the contracta substantially fixed price (approximately $1.7 billion based on Georgia Power's ownership interest).
Onagreement. In March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4,
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 whichwith the bankruptcy court approved on March 30, 2017.
EPC Contractor to allow construction to continue. The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired onin July 27, 2017.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017 of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.
Additionally, on June 9, 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, which was amendedWestinghouse provides facility design and restatedengineering services, procurement and technical support, and staff augmentation on July 20, 2017, for the EPC Contractor to transition construction management of Planta time and materials cost basis. The Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 isare 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EffectiveIn October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered intoexecuted the Bechtel Agreement, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will beis 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 connection withDecember 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue with construction of Plant Vogtle Units 3 and 4, (described below),with Southern Nuclear serving as project manager and Bechtel serving as the Vogtle Owners agreed onprimary construction contractor.
Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a term sheet to amendfull cost reforecast for the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, the holders of at least 90%project. Georgia Power's approximate proportionate share of the ownership interests inremaining estimated capital cost to complete Plant Vogtle Units 3 and 4 must voteby 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 September 30, 2018(b)
(4.3)
Remaining estimate to complete(a)
$4.1
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.
The table above reflects the $0.7 billion increase to continue construction if certain adverse events occur,the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted 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 (i)field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii)project and the Georgia PSC determinesPSC's order in the seventeenth VCM proceeding specifically states that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 willis not be recoveredsubject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in retail rates because suchthe current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs are deemed unreasonable or imprudent; or (iv) an increasecurrently included in the construction budget containedcontingency estimate for rate recovery as and when they are appropriately included in the seventeenth VCM report by more than $1 billion or extensionbase capital cost forecast. After considering the significant level of uncertainty that exists regarding the project schedule containedfuture recoverability of costs included in the seventeenth VCM report by more than one year. In addition, underconstruction contingency estimate since the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.
The term sheet also confirms 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.
The ultimate outcome of these matters cannot be determinedis subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.
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 only recently began initial operation in the global nuclear industry 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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paidscale); or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they areother
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

incurred priorissues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a)maintain the in-service capital cost forecast will be adjustedcurrent project schedule continue to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDCincrease significantly through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposesremainder of the AFUDC calculation, the ROE on costs between $4.418 billion2018 and $5.440 billion will alsointo 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be 10.00%retained and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revised Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
 (in billions)
Estimated cost to complete$4.2
CWIP as of September 30, 20174.6
Guarantee Obligations(1.7)
Estimated capital costs$7.1
Vogtle Cost Settlement Agreement Revised Forecast(5.7)
Estimated net additional capital costs$1.4
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
 Cancellation Cost Estimate
 (in billions)
CWIP as of September 30, 2017$4.6
Financing costs collected, net of tax1.5
Cancellation costs(*)
0.4
Guarantee Obligations(1.7)
Estimated net cancellation cost$4.8
(*)The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of September 30, 2017, 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. On September 28, 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. 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. 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 (E) 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.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 while construction proceeds.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 (ITAAC) and the related approvals by the NRC, may arise, while construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
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 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 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 continues,(as amended, and together with the risk remainsNovember 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that challengesthe Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with managementtheir performance as agent for the Vogtle Owners is limited to removal of contractors, subcontractors,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 vendors, labor productivity, fabrication, delivery, assembly,Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and installation4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of plant systems, structures,Plant Vogtle Units 3 and components,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, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC 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, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
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 Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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 expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and 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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 to 2022.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 combined with subsequent adverse action by the Georgia PSC could arisehave a material impact on Southern Company's results of operations, financial condition, and may further impact project scheduleliquidity.
The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and cost.approximately $188 million in related Customer Refunds). On August 31, 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.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in Item 1A ofherein and 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
As of September 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 September 2018, the DOE extended the conditional commitment to March 31, 2019. 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. See additional risksNote 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 1A8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein regarding the EPC Contractor's bankruptcy.for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
Bonus Depreciation
FINANCIAL CONDITION AND LIQUIDITY – "Excluding the Kemper IGCC, approximately $830 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. SeeCredit Rating Risk," Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined CycleRegulatory Matters," herein and Note (G)(H) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.information regarding the Tax Reform Legislation and related regulatory actions.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power
During the third quarter 2017,In April 2018, Southern Power begancompleted the final stage of 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. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to resultresulted in estimatednet state tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates andtotaling approximately $54 million, which were recorded in the first half of 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air qualitylaws and water standards,regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On October 2, 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings.
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 20, 2017, a purportedputative 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 IGCCCounty 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. OnIn June 12, 2017, the plaintiffs filed an amended
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. OnIn July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition onin September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit inMarch 29, 2018, the U.S. District Court for the Northern District of Georgia, that names as defendants Southern Company,Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain of its directors,claims against certain of its officers and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company unspecified actual damages and on her own behalf, attorneys' feesMississippi Power and costsdismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017,August 10, 2018, the court deferred this lawsuit until 30 days after certain further action indenied the purported securities class action complaint discussed above.motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
On May 15,In February 2017, Helen E. Piper Survivor's TrustJean Vineyard filed a shareholder derivative lawsuit and, in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 IGCC. EachCounty energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCCCounty energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. EachThe 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. EachThe plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia andMay 4, 2018, the court deferred the consolidated caseentered an order staying this lawsuit until 30 days after certain further actionthe resolution of any dispositive motions or any settlement, whichever is earlier, in the purportedputative securities class action complaint discussed above.action.
On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
The SEC is conducting a formal investigationSOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Mississippi Power concerningNote 1 to the estimated costs and expected in-service datefinancial statements of Southern Company under "Leveraged Leases" in Item 8 of the Kemper IGCC. Southern Company believes the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" hereinForm 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) 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 Kemper IGCC.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 September 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 September 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; however, it is not expected to have a material impact on the financial statements of Southern Company.time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.estimates.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date,Cost, Schedule, and Rate Recovery"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 Company in Item 7 ofNuclear serving as project manager and Bechtel serving as the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant,primary construction contractor, as well as Mississippi Power's June 28, 2017 suspensiona modification of the operation and start-upVogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the gasifier portion$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 Kemper IGCC,burden of proof on any party challenging such costs; (iii) Georgia Power would have the estimated constructionburden 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 project completion date are no longer considered significant accounting estimates. Significant accounting estimatesapproximately $188 million in related Customer Refunds) 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2017 financial statements presented herein includeGuarantee Settlement Agreement and approximately $188 million in related Customer Refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the overall assessment ofproject 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 did not seek rate recovery for the Kemper County energy facility$0.7 billion increase in costs included in the revised base capital cost forecast in the nineteenth VCM report filed with the Georgia PSC 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 estimatedbase capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs forincluded in the potential cancellation of the Kemper IGCC.
Whileconstruction contingency estimate since the ultimate dispositionoutcome of the gasification portions of the Kemper IGCC remainsthese matters is subject to the Mississippi PSC's jurisdiction, including the potential resolutionoutcome of the matters addressedfuture assessments by management, as well as Georgia PSC decisions in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippithese future regulatory proceedings, Georgia Power recorded an additionala total pre-tax charge to income in June 2017 of $2.8$1.1 billion ($2.00.8 billion after tax), in the second quarter 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 includesare based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated costs associatedcost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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 gasification portionsrequirements 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 plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costsNRC. Various design and other suspension costs through September 30, 2017.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. Any extension of the suspension period beyond December 31, 2017in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional suspensionbase capital costs of approximately $5$50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. InWhile 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 event the gasification portions of the projectcapital cost forecast that are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million arenot expected to be incurred.recoverable through regulated rates will be required to be charged to income and such charges could be material.
AsGiven the significant complexity involved in estimating the future costs to complete construction and start-up of September 30, 2017, Mississippi Power has recorded a totalPlant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility,any projected cost increases, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in 2017 and 2016, respectively.
Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and thepotential impact on Southern Company's results of operations and cash flows, Southern Company considers these items to be critical accounting
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle""Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle""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.
information regarding ASU No. 2016-02, In 2014,Leases (Topic 842) (ASU 2016-02). See Note (A) to the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidanceCondensed Financial Statements herein for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosuresinformation regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a definedrecently adopted accounting standards.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company expects the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.
Southern Company's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company's financial statements, Southern Company will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017,2016, the FASB issued ASU No. 2017-04, Intangibles – Goodwill2016-02, which requires lessees to recognize on the balance sheet a lease liability and Other (Topic 350): Simplifyinga right-of-use asset for all leases. ASU 2016-02 also changes the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removesrecognition, measurement, and presentation of expense associated with leases and provides clarification regarding the requirement to compare the implied fair valueidentification of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.
On March 10, 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 othercertain components of net periodic pensioncontracts that would represent a lease. The accounting required by lessors is relatively unchanged and postretirement benefit coststhere is no change to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligibleaccounting for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations.existing leveraged leases. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-122016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company is evaluatingwill adopt the new standard and expects to early adopt ASU 2017-12 effective January 1, 2018. 2019.
Southern Company has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
The Southern Company system is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. The Southern Company system has substantially completed its lease inventory and determined its most significant leases involve PPAs, real estate, and communication towers where certain of Southern Company's subsidiaries are the lessee and PPAs where certain of Southern Company's subsidiaries are the lessor. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2017-122016-02 is not expected to have aresult in recording lease liabilities and right-of-use assets on Southern Company's balance sheet each totaling approximately $2.1 billion, with no material impact on Southern Company's financial statements.statement of income.
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 September 30, 2017.2018. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $5.3$5.6 billion for the first nine months of 2017,2018, an increase of $1.0$0.3 billion from the corresponding period in 2016.2017. The increase in net cash provided from operating activities was primarily due to an increase of $1.5 billion in net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, partially offset byincreased fuel cost recovery and the timing of vendor payments. Net cash used for investing activities totaled $6.7$3.5 billion for the first nine months of 20172018 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, andpartially offset by proceeds from the Southern Power's renewable acquisitions.Company Gas Dispositions. Net cash provided fromused for financing activities totaled $1.3$2.3 billion for the first nine months of 20172018 primarily due to net issuancesredemptions and repurchases of long-term debt, common stock dividend payments, and short-term debt,a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities, and the issuance of common stock dividend payments.stock. 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 nine months of 20172018 include the reclassification of $5.1 billion and $3.2 billion in total assets and liabilities held for sale, respectively, primarily associated with Gulf Power, as well as decreases of $2.8 billion and $0.4 billion in total assets and liabilities, respectively, associated with the Southern Company Gas Dispositions. See Note (J) to the Condensed Financial Statements under "Assets Held for Sale" and "Southern Company Gas" herein for additional information. After adjusting for these changes, other significant balance sheet changes include an increase of $1.3$4.0 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, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largelyas well as an increase in AROs at Alabama Power, partially offset by the $2.9 billion write-downsecond quarter 2018 charge related to the construction of the gasification portions of the Kemper IGCC;Plant Vogtle Units 3 and 4; a decrease of $0.4 billion in income taxes receivable, current and unrecognized tax benefits primarily related to income tax refunds associated with deductible R&E expenditures; a decrease of $0.5 billion in acquisitions payable related to Southern Power; an increase of $2.3$2.6 billion in long-term debt (including amounts due within one year) primarily to fundresulting from the Southern Company system's continuous construction programs and for general corporate purposes; and a decreaserepayment of $0.7long-term debt; an increase of $1.8 billion in total common stockholder's equitynoncontrolling 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 estimated probable losses onCCR Rule. See Notes (A), (B), (F), and (J) to the Kemper IGCC, partially offset by the issuanceCondensed Financial Statements under "Asset Retirement Obligations," "Nuclear Construction," "Financing Activities," and "Southern Power – Sale of Solar Facility Interests," respectively, herein for additional shares of common stock.information.
At the end of the third quarter 2017,2018, the market price of Southern Company's common stock was $49.14$43.60 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99$24.18 per share, representing a market-to-book ratio of 205%180%, compared to $49.19, $25.00,$48.09, $23.99, and 197%201%, respectively, at the end of 2016.2017. Southern Company's common stock dividend for the third quarter 20172018 was $0.58$0.60 per share compared to $0.56$0.58 per share in the third quarter 2016.2017.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements and contractual obligations. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019, Alabama Power purchased and held $120 million of pollution control revenue bonds, and Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $2.6 billion will be required through September 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The Southern Company system's construction program is currently estimated to total approximately $8.8 billion for 2018, $8.2 billion for 2019, $7.2 billion for 2020, $7.0 billion for 2021, and $6.7 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction programs of thePlant 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, system, including estimatedrelating to assets divested during 2018 and held for sale at September 30, 2018. Estimated capital expenditures for new electric generating facilities and to comply with existing environmental statuteslaws and regulations, scheduled maturities of long-term debt, as well as related interest, derivative
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

obligations, preferredregulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity,$0.5 billion for 2018, 2019, 2020, 2021, and gas supply, asset management agreements, standby letters2022, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of creditCO2 emissions from fossil fuel-fired electric generating units.
The traditional electric operating companies also anticipate costs associated with closure and performance/surety bonds, trust funding requirements,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 unrecognized tax benefits. Subsequentevaluate the method and timing of compliance activities, are currently estimated to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of its Series Q 5.50% Senior Notes due October 15, 2017. An additional $3.2be approximately $0.3 billion, will be required through September 30,$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 fund maturities of long-term debt. Seethese cost estimates during the fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Sources of CapitalAsset Retirement Obligations" hereinherein. 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.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 statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I)(J) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear"Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.expenditures.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-termborrowings from financial institutions, and debt term loans, and external security issuances.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 capital and debt issuances in 2017,2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, term loans, short-term borrowings from financial institutions, and equity contributions or loans from Southern Company. In addition, Southern Power also plans to utilize tax equity partnership contributions. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding)Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2017,2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. OnIn July 27, 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OnIn September 28, 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 March 31, 2019, 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. 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 (E)(F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear 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 September 30, 2017,2018, Southern Company's current liabilities exceeded current assets by $3.4$3.6 billion due to long-term debt that is due within one year of $3.5$3.0 billion (comprised of(including approximately $1.0$1.3 billion at the parent company, $0.3 billion at Alabama Power, $0.3$0.5 billion at Georgia Power, $1.0$0.2 billion at Mississippi Power, and $0.9$0.5 billion at Southern Power)Company Gas) and notes payable of $2.6 billion (comprised of(including approximately $1.1$2.0 billion at the parent company, $0.4$0.1 billion at Georgia Power, $0.1 billion at Gulf Power, $0.2 billion at Southern Power, and $0.9$0.1 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2017,2018, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 20172018 were as follows:
Expires   
Executable Term
Loans
 Expires Within One YearExpires   
Executable Term
Loans
 
Expires Within
One Year
Company20172018201920202022 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
2018201920202022 Total Unused 
One
Year
 
Term
Out
 
No Term
Out
(in millions)(in millions)
Southern Company(a)
$—
$—
$—
$—
$2,000
 $2,000
 $2,000
 $—
 $—
 $—
 $—
$—
$—
$—
$2,000
 $2,000
 $1,999
 $—
 $—
 $—
Alabama Power—
35
—
500
800
 1,335
 1,335
 —
 —
 —
 35
—
33
500
800
 1,333
 1,333
 —
 —
 33
Georgia Power—
—
—
—
1,750
 1,750
 1,732
 —
 —
 —
 —
—
—
—
1,750
 1,750
 1,736
 —
 —
 —
Gulf Power30
195
25
30
—
 280
 280
 45
 —
 —
 40
20
25
235
—
 280
 280
 45
 45
 —
Mississippi Power100
—
—
—
—
 100
 100
 —
 —
 —
 100
—
100
—
—
 100
 100
 —
 —
 —
Southern Power Company(b)
—
—
—
—
750
 750
 728
 —
 —
 —
 —
—
—
—
750
 750
 728
 —
 —
 —
Southern Company Gas(c)
—
—
—
—
1,900
 1,900
 1,861
 —
 —
 —
 —
—
—
—
1,900
 1,900
 1,895
 —
 —
 —
Other—
30
—
—
—
 30
 30
 20
 —
 20
 10
—
30
—
—
 30
 30
 —
 —
 30
Southern Company Consolidated$130
$260
$25
$530
$7,200
 $8,145
 $8,066
 $65
 $—
 $20
 $185
$20
$188
$735
$7,200
 $8,143
 $8,101
 $45
 $45
 $63
(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, of which $111 million has been used for letters of credit and $922 million remains unused at September 30, 20172018.
(c)
Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.21.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017,2018, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. NoneAll but $40 million of the bank credit arrangements do not contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 20172018 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement.billion. In addition, at September 30, 2017,2018, the traditional electric operating companies had approximately $699$573 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $402018, Alabama Power purchased and held approximately $120 million of theseits outstanding pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketedrequired to the public in a long-term fixed rate mode.be remarketed.
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), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:
 Short-term Debt at September 30, 2017 
Short-term Debt During the Period(*)
 
Short-term Debt at
September 30, 2018
 
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 $1,725
 1.5% $1,895
 1.5% $2,284
 $611
 2.5% $1,323
 2.4% $3,008
Short-term bank debt 854
 2.0% 938
 2.1% 1,017
 1,953
 2.9% 1,790
 3.0% 2,003
Total $2,579
 1.7% $2,833
 1.7%   $2,564
 2.8% $3,113
 2.7%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.2018.
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At September 30, 2017,2018, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and interest rate management.management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 20172018 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements		Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and/or Baa2$38
$38
At BBB- and/or Baa3$647
$578
At BB+ and/or Ba1(*)
$2,352
$2,120
(*)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 March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017,February 26, 2018, Moody's revised its rating outlook for Mississippi Power from under reviewstable to stable.positive. On August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.
On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Also 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 August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A.
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.
On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3.
On September 28, 2018, Moody's revised its rating outlooks for Southern Company, Alabama Power, and Georgia Power from negative to stable.
Also on September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and its subsidiaries (excluding Gulf Power and Mississippi Power).
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 3 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including 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 nine months of 2017,2018, Southern Company issued approximately 10.69.2 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $479$338 million.
In addition, during the second and third quarters of 2017,quarter 2018, Southern Company issued a total of approximately 2.712.1 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134$540 million, net of $1.1approximately $5 million in feescommissions. Subsequent to September 30, 2018, Southern Company issued an additional approximately 2.5 million shares of common stock through at-the-market issuances and received cash proceeds of approximately $107 million, net of approximately $1 million in commissions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2017:2018:
Company
Senior
Note Issuances
 
Senior
Note Maturities and Redemptions
 
Revenue
Bond
Maturities, Redemptions, and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt Redemptions
and
Maturities(a)
Senior
Note
Issuances
 Senior Note Maturities, Redemptions, and Repurchases 
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)
$300
 $400
 $—
 $500
 $400
$750
 $1,000
 $—
 $—
 $—
Alabama Power550
 200
 36
 —
 —
500
 —
 —
 —
 —
Georgia Power1,350
 450
 65
 370
 13
—
 1,000
 469
 —
 107
Gulf Power300
 85
 —
 6
 —
Mississippi Power—
 —
 —
 40
 893
600
 —
 43
 —
 900
Southern Power—
 —
 —
 43
 4
—
 350
 —
 —
 420
Southern Company Gas(c)
450
 —
 —
 200
 22
Southern Company Gas—
 —
 200
 100
 —
Other—
 —
 —
 —
 12
—
 —
 —
 —
 10
Elimination(d)
—
 —
 —
 (40) (599)
Elimination(c)
—
 —
 —
 —
 (1)
Southern Company Consolidated$2,950
 $1,135
 $101
 $1,119
 $745
$1,850
 $2,350
 $712
 $100
 $1,436
(a)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(b)Represents the Southern Company parent entity.
(c)
The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.
(d)Includes intercompany loans from Southern Company to Mississippi Power andRepresents reductions in affiliate capital lease obligations at Georgia Power. These transactionsPower, which are eliminated in Southern Company's Consolidated Financial Statements.
In March 2017,Except as otherwise described herein, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amountand its subsidiaries used the proceeds of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057debt issuances for their redemptions and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were usedmaturities shown in the table above, to repay short-term indebtedness, and for other general corporate purposes.purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.
Also in June 2017,In March 2018, Southern Company entered into two $100a $900 million aggregate principal amountshort-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bearbearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.LIBOR, which was repaid in August 2018.
In August 2017,April 2018, Southern Company borrowed $250 million pursuant to ana short-term uncommitted bank credit arrangement, which bearsbearing interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.
In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to a short-term uncommitted bank credit arrangement.
In the third quarter 2018, Southern Company repaid at maturity $500 million aggregate principal amount of 1.55% Senior Notes and $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes.
Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The proceeds were used for working capitalIndustrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. These bonds may be remarketed to the public in the future.
In January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.
In May 2018, through cash tender offers, Georgia Power repurchased and other general corporate purposes.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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Also in August 2017, Southern Company repaid at maturity $400the $500 million aggregate principal amount outstanding of its Series 2014A 1.30%2009A 5.95% Senior Notes.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.
Except as described herein, Southern Company's subsidiaries usedIn March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. The proceeds of this loan, together with the proceeds of the debtMississippi Power's $600 million senior notes issuances, shown in the table above for their redemptions and maturities shown in the table above,were used to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs.
In September 2017, Alabama Power issued 10Mississippi Power's $900 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.unsecured floating rate term loan.
Subsequent to September 30, 2017, Alabama2018, Mississippi Power repaid at maturity $325completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series Q 5.50%G 5.40% Senior Notes due October 15, 2017.July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.
In June 2017, GeorgiaMay 2018, Southern Power entered into threetwo short-term floating rate bank loans, ineach for an aggregate principal amountsamount of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also
During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to certain of its renewable facilities. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Prior to its sale, in June 2017, Georgia Powerthe second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.
In May 2018, Southern Company Gas Capital borrowed $500$95 million pursuant to ana short-term uncommitted bank credit arrangement, which bearsguaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Georgia PowerSouthern Company Gas Capital and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loansof the loan were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
short-term debt. In August 2017, Georgia PowerJuly 2018, Southern Company Gas Capital repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.this loan.
In July 2017,2018, Nicor Gas agreed to issue $400$300 million aggregate principal amount of first mortgage bonds in a private placement. Onplacement, $100 million of which was issued in August 10, 2017, Nicor2018 and $200 million of which was issued in November 2018.
Subsequent to September 30, 2018, Southern Company Gas issued $100Capital repaid at maturity $155 million aggregate principal amount of First Mortgage Bonds 3.03%3.50% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.B Senior Notes.
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.

Table of Contents

PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2017,2018, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas respectively, herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (C)(D) and Note (H)(I) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
(b)Changes in internal controls over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 20172018 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.

Table of Contents

ALABAMA POWER COMPANY

Table of Contents

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$1,595
 $1,629
 $4,155
 $4,139
$1,584
 $1,595
 $4,208
 $4,155
Wholesale revenues, non-affiliates77
 82
 210
 211
74
 77
 213
 210
Wholesale revenues, affiliates18
 18
 83
 49
14
 18
 96
 83
Other revenues50
 56
 158
 162
68
 50
 199
 158
Total operating revenues1,740
 1,785
 4,606
 4,561
1,740
 1,740
 4,716
 4,606
Operating Expenses:              
Fuel343
 410
 944
 973
356
 343
 1,028
 944
Purchased power, non-affiliates57
 63
 132
 139
64
 57
 176
 132
Purchased power, affiliates55
 41
 117
 129
69
 55
 149
 117
Other operations and maintenance391
 348
 1,134
 1,097
401
 406
 1,191
 1,177
Depreciation and amortization185
 177
 549
 524
192
 185
 570
 549
Taxes other than income taxes93
 96
 284
 286
97
 93
 289
 284
Total operating expenses1,124
 1,135
 3,160
 3,148
1,179
 1,139
 3,403
 3,203
Operating Income616
 650
 1,446
 1,413
561
 601
 1,313
 1,403
Other Income and (Expense):              
Allowance for equity funds used during construction11
 7
 27
 23
16
 11
 43
 27
Interest expense, net of amounts capitalized(76) (77) (229) (224)(82) (76) (240) (229)
Other income (expense), net(5) (5) (8) (16)9
 10
 24
 35
Total other income and (expense)(70) (75) (210) (217)(57) (55) (173) (167)
Earnings Before Income Taxes546
 575
 1,236
 1,196
504
 546
 1,140
 1,236
Income taxes216
 219
 493
 462
127
 216
 272
 493
Net Income330
 356
 743
 734
377
 330
 868
 743
Dividends on Preferred and Preference Stock5
 4
 14
 13
4
 5
 11
 14
Net Income After Dividends on Preferred and Preference Stock$325
 $352
 $729
 $721
$373
 $325
 $857
 $729

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Net Income$330
 $356
 $743
 $734
$377
 $330
 $868
 $743
Other comprehensive income (loss):              
Qualifying hedges:              
Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively—
 —
 —
 (2)
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $2, respectively		1
 1
 3
 3
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $1, and $2, respectively		1
 1
 3
 3
Total other comprehensive income (loss)1
 1
 3
 1
1
 1
 3
 3
Comprehensive Income$331
 $357
 $746
 $735
$378
 $331
 $871
 $746
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

Table of Contents

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$868
 $743
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total683
 666
Deferred income taxes104
 260
Allowance for equity funds used during construction(43) (27)
Settlement of asset retirement obligations(31) (20)
Other, net(6) 59
Changes in certain current assets and liabilities —   
-Receivables(207) (163)
-Prepayments(26) (28)
-Materials and supplies(69) (29)
-Other current assets66
 33
-Accounts payable(194) (125)
-Accrued taxes225
 159
-Accrued compensation(41) (48)
-Retail fuel cost over recovery—
 (76)
-Other current liabilities60
 7
Net cash provided from operating activities1,389
 1,411
Investing Activities:   
Property additions(1,529) (1,211)
Nuclear decommissioning trust fund purchases(207) (174)
Nuclear decommissioning trust fund sales207
 174
Cost of removal, net of salvage(78) (82)
Change in construction payables30
 105
Other investing activities(23) (29)
Net cash used for investing activities(1,600) (1,217)
Financing Activities:   
Proceeds —   
Senior notes500
 550
Capital contributions from parent company495
 337
Preferred stock—
 250
Redemptions —   
Senior notes—
 (200)
Pollution control revenue bonds—
 (36)
Payment of common stock dividends(602) (536)
Other financing activities(24) (26)
Net cash provided from financing activities369
 339
Net Change in Cash, Cash Equivalents, and Restricted Cash158
 533
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period544
 420
Cash, Cash Equivalents, and Restricted Cash at End of Period$702
 $953
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $15 and $10 capitalized for 2018 and 2017, respectively)$220
 $217
Income taxes, net30
 146
Noncash transactions — Accrued property additions at end of period275
 189
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

Table of Contents

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $702
 $544
Receivables —    
Customer accounts receivable 455
 355
Unbilled revenues 159
 162
Under recovered regulatory clause revenues 48
 —
Affiliated 68
 43
Other accounts and notes receivable 54
 55
Accumulated provision for uncollectible accounts (9) (9)
Fossil fuel stock 117
 184
Materials and supplies 536
 458
Prepaid expenses 59
 85
Other regulatory assets, current 141
 124
Other current assets 8
 5
Total current assets 2,338
 2,006
Property, Plant, and Equipment:    
In service 29,568
 27,326
Less: Accumulated provision for depreciation 9,932
 9,563
Plant in service, net of depreciation 19,636
 17,763
Nuclear fuel, at amortized cost 316
 339
Construction work in progress 1,457
 908
Total property, plant, and equipment 21,409
 19,010
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 63
 67
Nuclear decommissioning trusts, at fair value 938
 903
Miscellaneous property and investments 127
 124
Total other property and investments 1,128
 1,094
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 236
 239
Deferred under recovered regulatory clause revenues 88
 54
Other regulatory assets, deferred 1,209
 1,272
Other deferred charges and assets 202
 189
Total deferred charges and other assets 1,735
 1,754
Total Assets $26,610
 $23,864
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months Ended September 30,
 2017 2016
 (in millions)
Operating Activities:   
Net income$743
 $734
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total666
 634
Deferred income taxes260
 267
Allowance for equity funds used during construction(27) (23)
Pension, postretirement, and other employee benefits(4) (14)
Other, net43
 (12)
Changes in certain current assets and liabilities —   
-Receivables(163) (4)
-Fossil fuel stock34
 18
-Other current assets(58) (46)
-Accounts payable(125) (113)
-Accrued taxes159
 207
-Accrued compensation(48) (22)
-Retail fuel cost over recovery(76) (104)
-Other current liabilities7
 19
Net cash provided from operating activities1,411
 1,541
Investing Activities:   
Property additions(1,211) (947)
Nuclear decommissioning trust fund purchases(174) (275)
Nuclear decommissioning trust fund sales174
 275
Cost of removal, net of salvage(82) (70)
Change in construction payables105
 (37)
Other investing activities(29) (28)
Net cash used for investing activities(1,217) (1,082)
Financing Activities:   
Proceeds —   
Senior notes550
 400
Capital contributions from parent company337
 253
Preferred stock250
 —
Other long-term debt—
 45
Redemptions —

 
Pollution control revenue bonds(36) —
Senior notes(200) (200)
Payment of common stock dividends(536) (574)
Other financing activities(26) (21)
Net cash provided from (used for) financing activities339
 (97)
Net Change in Cash and Cash Equivalents533
 362
Cash and Cash Equivalents at Beginning of Period420
 194
Cash and Cash Equivalents at End of Period$953
 $556
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively)$217
 $215
Income taxes, net146
 (70)
Noncash transactions — Accrued property additions at end of period189
 84
The accompanying notes as they relate to Alabama Power are an integral partTable of these condensed financial statements.Contents

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30, 2017 At December 31, 2016
  (in millions)
Current Assets:    
Cash and cash equivalents $953
 $420
Receivables —    
Customer accounts receivable 428
 348
Unbilled revenues 149
 146
Other accounts and notes receivable 47
 27
Affiliated 45
 40
Accumulated provision for uncollectible accounts (8) (10)
Fossil fuel stock 171
 205
Materials and supplies 455
 435
Prepaid expenses 58
 34
Other regulatory assets, current 122
 149
Other current assets 5
 11
Total current assets 2,425
 1,805
Property, Plant, and Equipment:    
In service 26,619
 26,031
Less: Accumulated provision for depreciation 9,463
 9,112
Plant in service, net of depreciation 17,156
 16,919
Nuclear fuel, at amortized cost 314
 336
Construction work in progress 928
 491
Total property, plant, and equipment 18,398
 17,746
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 65
 66
Nuclear decommissioning trusts, at fair value 869
 792
Miscellaneous property and investments 121
 112
Total other property and investments 1,055
 970
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 525
 525
Deferred under recovered regulatory clause revenues 17
 150
Other regulatory assets, deferred 1,191
 1,157
Other deferred charges and assets 178
 163
Total deferred charges and other assets 1,911
 1,995
Total Assets $23,789
 $22,516
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At September 30, 2017 At December 31, 2016 At September 30, 2018 At December 31, 2017
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $325
 $561
 $321
 $—
Accounts payable —        
Affiliated 275
 297
 341
 327
Other 376
 433
 425
 585
Customer deposits 92
 88
 96
 92
Accrued taxes —        
Accrued income taxes 115
 45
 97
 9
Other accrued taxes 128
 42
 132
 45
Accrued interest 75
 78
 81
 77
Accrued compensation 151
 193
 169
 205
Asset retirement obligations, current 111
 7
Other regulatory liabilities, current 4
 85
 57
 1
Other current liabilities 50
 76
 46
 52
Total current liabilities 1,591
 1,898
 1,876
 1,400
Long-term Debt 7,083
 6,535
 7,803
 7,628
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 4,919
 4,654
 2,882
 2,760
Deferred credits related to income taxes 60
 65
 2,051
 2,082
Accumulated deferred ITCs 118
 110
 107
 112
Employee benefit obligations 289
 300
 283
 304
Asset retirement obligations 1,564
 1,503
 3,090
 1,702
Other cost of removal obligations 630
 684
 542
 609
Other regulatory liabilities, deferred 93
 100
 52
 84
Other deferred credits and liabilities 51
 63
 48
 63
Total deferred credits and other liabilities 7,724
 7,479
 9,055
 7,716
Total Liabilities 16,398
 15,912
 18,734
 16,744
Redeemable Preferred Stock 329
 85
 291
 291
Preference Stock 196
 196
Common Stockholder's Equity:        
Common stock, par value $40 per share —        
Authorized — 40,000,000 shares        
Outstanding — 30,537,500 shares 1,222
 1,222
 1,222
 1,222
Paid-in capital 2,961
 2,613
 3,490
 2,986
Retained earnings 2,711
 2,518
 2,902
 2,647
Accumulated other comprehensive loss (28) (30) (29) (26)
Total common stockholder's equity 6,866
 6,323
 7,585
 6,829
Total Liabilities and Stockholder's Equity $23,789
 $22,516
 $26,610
 $23,864
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



THIRD QUARTER 20172018 vs. THIRD QUARTER 20162017
AND
YEAR-TO-DATE 20172018 vs. YEAR-TO-DATE 20162017


OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information on Alabama Power's established retail tariff.
Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
(% change)
(change in millions)
(% change)
$(27) (7.7) $8 1.1
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)
(% change)
(change in millions)
(% change)
$48 14.8 $128 17.6
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 20172018 was $325$373 million compared to $352$325 million for the corresponding period in 2016. The decrease was primarily related to a decrease in retail revenues associated with milder weather and lower customer usage in the third quarter 2017 compared to the corresponding period in 2016 and an increase in non-fuel operations and maintenance expenses. The decrease was partially offset by an increase in rates under Rate RSE effective January 1, 2017.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 20172018 was $729$857 million compared to $721$729 million for the corresponding period in 2016. The increase was2017. These increases were primarily related to an increase in rates under Rate RSE effective January 1, 2017, partially offset by a decrease in retail revenues associated with mildercolder weather in the first quarter 2018 and lower customer usage for year-to-date 2017warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periodperiods in 2016,2017 and an increasea decrease in non-fuel operationsincome tax expense, partially offset by customer bill credits related to the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and maintenance expenses.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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Retail Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(34) (2.1) $16 0.4
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(11) (0.7) $53 1.3
In the third quarter 2017,2018, retail revenues were $1.60$1.58 billion compared to $1.63$1.60 billion for the corresponding period in 2016.2017. For year-to-date 2017,2018, retail revenues were $4.16$4.21 billion compared to $4.14$4.16 billion for the corresponding period in 2016.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



2017.
Details of the changes in retail revenues were as follows:
Third Quarter 2017
Year-to-Date 2017Third Quarter 2018
Year-to-Date 2018
(in millions)
(% change)
(in millions)
(% change)(in millions)
(% change)
(in millions)
(% change)
Retail – prior year$1,629
   $4,139
  $1,595
   $4,155
  
Estimated change resulting from –              
Rates and pricing85
 5.2
 240
 5.8
(87) (5.5) (195) (4.7)
Sales decline(18) (1.1) (31) (0.7)(2) (0.1) (8) (0.1)
Weather(50) (3.1) (116) (2.8)37
 2.3
 130
 3.1
Fuel and other cost recovery(51) (3.1) (77) (1.9)41
 2.6
 126
 3.0
Retail – current year$1,595
 (2.1)% $4,155
��0.4%$1,584
 (0.7)% $4,208
 1.3%
Revenues associated with changes in rates and pricing increaseddecreased in the third quarter and year-to-date 20172018 when compared to the corresponding periods in 20162017 primarily due to an increase in ratescustomer bill credits related to the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements under Rate RSE effective January 1, 2017. See"Regulatory Matters – Alabama Power" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 20172018 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth.2017. Weather-adjusted commercial KWH sales decreased 2.3%1.1% and 1.4% for the third quarter and year-to-date 2018, respectively, and weather-adjusted residential KWH sales decreased 0.3% and 0.5% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 respectively, primarily due to lower customer usage resulting from customer initiatives inrelated to energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth.efficiency. Industrial KWH sales increased 1.8%1.3% and 0.6%2.4% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 respectively, as a result of an increase in demand resulting from changes in production levels primarily in the primary metals chemicals,sector, largely due to strong domestic demand for steel and mining sectors,aluminum, and in the pipelines sector, partially offset by a decrease in demand fromin the pipeline sector.paper and chemicals sectors, primarily due to customer maintenance outages and on-site cogeneration.
Revenues resulting from changes in weather decreasedincreased in the third quarter and year-to-date 20172018 due to mildercolder weather experiencedin the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2016.2017. For the third quarter 2017,2018, the resulting decreasesincreases were 5.1%3.9% and 2.4%2.2% for residential and commercial sales revenues, respectively. For year-to-date 2017,2018, the resulting decreasesincreases were 5.2%5.7% and 1.8%2.3% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreasedincreased in the third quarter and year-to-date 20172018 when compared to the corresponding periods in 20162017 primarily due to a decreaseincreases in KWH generation and a decrease in the average cost of fuel.
Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Wholesale Revenues – Affiliates
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$— — $34 69.4
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(4) (22.2) $13 15.7
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
For year-to-date 2018, wholesale revenues from sales to affiliates were $96 million compared to $83 million for the corresponding period in 2017. The increase was primarily due to a 12% increase in the price of energy and a 3% increase in KWH sales as a result of increased demand due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$18 36.0 $41 25.9
In the third quarter 2018, other revenues were $68 million compared to $50 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $199 million compared to $158 million for the corresponding period in 2017. These increases were primarily due to revenues related to unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606. The year-to-date 2018 increase was partially offset by decreases in open access transmission tariff revenues primarily due to expected declines in customers' needs and a lower rate related to the Tax Reform Legislation.
Fuel and Purchased Power Expenses
 Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
 (change in millions)
(% change) (change in millions) (% change)
Fuel$13
 3.8 $84
 8.9
Purchased power – non-affiliates7
 12.3 44
 33.3
Purchased power – affiliates14
 25.5 32
 27.4
Total fuel and purchased power expenses$34
   $160
  
In the third quarter 2018, fuel and purchased power expenses were $489 million compared to $455 million for the corresponding period in 2017. The increase was primarily due to a $23 million increase related to the volume of KWHs generated and purchased and a $16 million increase related to the average cost of fuel, partially offset by a $5 million decrease in the average cost of purchased power.
For year-to-date 2018, fuel and purchased power expenses were $1.35 billion compared to $1.19 billion for the corresponding period in 2017. The increase was primarily due to a $98 million increase related to the volume of KWHs generated and purchased and a $32 million increase related to the average cost of fuel.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



marginal cost and energy purchases are generallyIn addition, fuel expense increased $30 million year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset by energy revenues through Alabama Power's energy cost recovery clauses.
For year-to-date 2017, wholesale revenues from sales to affiliates were $83 million compared to $49 millionunder recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for the corresponding period in 2016. The increase was primarily due to a 52% increase in KWH sales as a result of supporting Southern Company system transmission reliability and an 11% increase in the price of energy due to an increase in natural gas prices.
Other Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(6) (10.7) $(4) (2.5)
In the third quarter 2017, other revenues were $50 million compared to $56 million for the corresponding period in 2016. The decrease was primarily due to lower open access transmission tariff revenues as a result of rate adjustments.
Fuel and Purchased Power Expenses
 Third Quarter 2017
vs.
Third Quarter 2016		 Year-to-Date 2017
vs.
Year-to-Date 2016
 (change in millions)
(% change) (change in millions) (% change)
Fuel$(67) (16.3) $(29) (3.0)
Purchased power – non-affiliates(6) (9.5) (7) (5.0)
Purchased power – affiliates14
 34.1 (12) (9.3)
Total fuel and purchased power expenses$(59)   $(48)  
In the third quarter 2017, fuel and purchased power expenses were $455 million compared to $514 million for the corresponding period in 2016. The decrease was primarily due to a $43 million net decrease related to the volume of KWHs generated and purchased and a $16 million decrease related to the average cost of fuel.
For year-to-date 2017, fuel and purchased power expenses were $1.19 billion compared to $1.24 billion for the corresponding period in 2016. The decrease was primarily due to a $53 million decrease in the volume of KWHs purchased and a $34 million decrease related to the average cost of fuel. This decrease was partially offset by a $35 million increase in the average cost of purchased power.additional information.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.
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:
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017
Year-to-Date 2016Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018
Year-to-Date 2017
Total generation (in billions of KWHs)
16 18 46 4616 16 47 46
Total purchased power (in billions of KWHs)
2 2 5 63 2 6 5
Sources of generation (percent) —
  
Coal52 59 49 5154 52 52 49
Nuclear24 22 25 2424 24 22 25
Gas19 18 20 1918 19 19 20
Hydro5 1 6 64 5 7 6
Cost of fuel, generated (in cents per net KWH) —
 
Cost of fuel, generated (in cents per net KWH)(a) —
 
Coal2.61 2.73 2.61 2.802.74 2.61 2.74 2.61
Nuclear0.75 0.77 0.75 0.780.78 0.75 0.77 0.75
Gas2.72 2.85 2.74 2.622.80 2.72 2.72 2.74
Average cost of fuel, generated (in cents per net KWH)(a)(b)
2.17 2.32 2.15 2.252.27 2.17 2.27 2.15
Average cost of purchased power (in cents per net KWH)(b)(c)
5.65 5.70 5.57 4.815.43 5.65 5.59 5.57
(a)
Cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment for year-to-date 2018 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.
(b)
(c)		Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2017,2018, fuel expense was $343$356 million compared to $410$343 million for the corresponding period in 2016.2017. The decreaseincrease was primarily due to an 18.4%a 16.6% decrease in the volume of KWHs generated by hydro facilities due to lower rainfall, a 5.0% increase in the average cost of coal per KWH generated, a 4.6%4.0% increase in the average cost of nuclear fuel per KWH generated, and a 3.9% decrease in the volume of KWHs generated by nuclear facilities due to the timing of outages. In addition, the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, increased 2.9% and the volume of KWHs generated by coal increased 2.0%. These increases were partially offset by an 8.4% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2018, fuel expense was $1.03 billion compared to $944 million for the corresponding period in 2017. The increase was primarily due to a 10.8% decrease in the volume of KWHs generated by nuclear facilities due to outages, a 6.9% increase in the volume of KWHs generated by coal, and a 4.4% decrease5.0% increase in the average cost of coal per KWH generated. In addition, there was a 194.0%These increases were partially offset by an 11.7% increase in the volume of KWHs generated by hydro facilities as a result of significantly more rainfall in 2017.
For year-to-date 2017, fuel expense was $944 million compared to $973 million for the corresponding period in 2016. The decrease was primarily due to a 6.8% decrease in the average costtiming of coal per KWH generatedrainfall and a 2.0%4.1% decrease in the volume of KWHs generated by coal. The decrease was partially offset by a 4.8% increase in the volume of KWHs generated by natural gas and a 4.6% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.
Purchased Power – Affiliates
In the third quarter 2017, purchased power expense from affiliates was $55 million compared to $41 million for the corresponding period in 2016. The increase was primarily related to a 55.2% increase in the amount of energy purchased due to an increase in plant outages and increased purchases from Southern Electric Generating Company (SEGCO). The increase was partially offset by a 14.5% decrease in the average cost per KWH of capacity and energy at SEGCO. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information.
For year-to-date 2017, purchased power expense from affiliates was $117 million compared to $129 million for the corresponding period in 2016. The decrease was primarily related to a 26.6% decrease in the amount of energy purchased due to a decrease in demand as a result of milder weather in 2017, partially offset by a 22.9% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.gas.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In addition, fuel expense increased $30 million year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.
Purchased Power – Non-Affiliates
In the third quarter 2018, purchased power expense from non-affiliates was $64 million compared to $57 million for the corresponding period in 2017. The increase was primarily related to a 14.8% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, purchased power expense from non-affiliates was $176 million compared to $132 million for the corresponding period in 2017. The increase was primarily related to a 24.3% increase in the amount of energy purchased and a 6.7% increase in the average cost of purchased power per KWH due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2018, purchased power expense from affiliates was $69 million compared to $55 million for the corresponding period in 2017. The increase was primarily related to a 28% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, purchased power expense from affiliates was $149 million compared to $117 million for the corresponding period in 2017. The increase was primarily related to a 35% increase in the amount of energy purchased as a result of colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$43 12.4 $37 3.4
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(5) (1.2) $14 1.2
In the third quarter 2017,For year-to-date 2018, other operations and maintenance expenses were $391$1.19 billion compared to $1.18 billion for the corresponding period in 2017. The increase was primarily due to $33 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 $29 million primarily due to additional line maintenance. These increases were partially offset by a $23 million decrease in steam generation costs primarily due to the timing of outages, an $8 million decrease in employee benefits as a result of amounts capitalized in connection with an increase in construction projects, a $7 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects, and a $6 million decrease in property insurance primarily due to the receipt of refunds.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 3.8 $21 3.8
In the third quarter 2018, depreciation and amortization was $192 million compared to $348$185 million for the corresponding period in 2016. The increase was primarily due to increases of $26 million in scheduled generation outage costs, $11 million in vegetation management costs, and $3 million in employee compensation and benefit costs, including pension costs.
2017. For year-to-date 2017, other operations and maintenance expenses were $1.13 billion compared to $1.10 billion for the corresponding period in 2016. The increase was primarily due to increases of $31 million in vegetation management costs, $10 million in nuclear generation plant improvement costs, and $7 million in employee compensation and benefit costs, including pension costs, partially offset by an $11 million decrease in contract services.
Depreciation and Amortization
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$8 4.5 $25 4.8
In the third quarter 2017,2018, depreciation and amortization was $185$570 million compared to $177$549 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $549 million compared to $524 million for the corresponding period in 2016.2017. These increases were primarily due to additional plant in service related to steam generation, transmission, and an increase in depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and asset retirement obligation recovery, partially offset by a decrease in distribution-related depreciation rates.distribution assets. See Note 1 to the financial statements of Alabama Power under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Income TaxesAllowance for Equity Funds Used During Construction
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(3) (1.4) $31 6.7
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$5 45.5 $16 59.3
For year-to-date 2017, income taxes were $493In the third quarter 2018, AFUDC equity was $16 million compared to $462$11 million for the corresponding period in 2016. The2017. For year-to-date 2018, AFUDC equity was $43 million compared to $27 million for the corresponding period in 2017. These increases were primarily due to an increase in capital expenditures related to environmental and transmission projects.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 7.9 $11 4.8
In the third quarter 2018, interest expense, net of amounts capitalized was $82 million compared to $76 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $240 million compared to $229 million for the corresponding period in 2017. These increases were primarily due to an increase in the average debt outstanding and higher interest rates, partially offset by an increase in the amounts capitalized.
Other Income (Expense), Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(1) (10.0) $(11) (31.4)
For year-to-date 2018, other income (expense), net was $24 million compared to $35 million for the corresponding period in 2017. This decrease was primarily due to higher pre-tax earnings, unrecognized tax benefits relatedthe reclassification of revenues and expenses associated with unregulated sales of products and services to certain state deductionsother 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Income Taxes
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(89) (41.2) $(221) (44.8)
In the third quarter 2018, income taxes were $127 million compared to $216 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $272 million compared to $493 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 prior year tax return actualization.lower pre-tax earnings. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" and Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be driven primarilyimpacted by customer growth. Earnings will also depend upon
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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.transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. 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
ComplianceAlabama 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 relatedassociated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to federal and statecomply with environmental statuteslaws 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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" and "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Environmental StatutesLaws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final effluent guidelinesrulemaking 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 final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these mattersany legal challenges and cannot be determined at this time.
Global Climate IssuesCoal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues"Environmental Laws and Regulations – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information.information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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 March 28, 2017,October 15, 2018, the U.S. President signedCourt of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Alabama Power is evaluating the extent of potential impacts on legacy units. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
On April 20, 2018, the Alabama Environmental Management Commission approved a state CCR rule that has been provided to the EPA for a six-month review period. This state CCR rule is generally consistent with the federal CCR Rule. The ultimate outcome of this matter cannot be determined at this time.
In June 2018, Alabama Power recorded an executive order directing agenciesincrease of approximately $1.2 billion to review actionsits AROs related to the CCR Rule. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that potentially burdenadditional 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 development or useplanned 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 the level of domestically produced energy resources. The executive orderwork becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



specifically directs the EPA to review the Clean Power PlanAbsent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.
Nuclear Decommissioning
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.
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.
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.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Alabama Power has ownership interests in 20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Alabama Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Alabama Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Alabama Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Alabama Power's) and Southern Power's market power proceedingproceedings related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Alabama Power's) and Southern Power's June 30,2014 and 2017 triennial updated market power analysis. Theanalyses.
On May 4, 2018, the FERC directedissued an order terminating both proceedings, finding that the traditional electric operating companies (including Alabama Power) and Southern Power to show cause within 60 days whysatisfy the FERC's standards for market-based rate authority should not be revoked in certain areas adjacent torates. On May 9, 2018, the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Alabama Power) and Southern Power expectmade the compliance filing required by the order. These proceedings are concluded.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to make a filing within the specified 60 days respondingbe material to the FERC's order.
Alabama Power's results of operations. The ultimate outcome of these mattersthis 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.
On July 6, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating the FERC's 2013 order issuing a new 30-year license to Alabama Power for seven hydroelectric developments on the Coosa River and remanding the proceeding to the FERC for further proceedings. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and accounting orders. Thethe recovery balance of each regulatory clause for Alabama Power.
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is reportedto achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Alabama Power in Item 7 of the Form 10-K for additional information.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 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. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
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 September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Alabama Power under "Federal Tax Reform Legislation" and "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-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.
Request for Proposals for Future Generation
On September 21, 2018, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than 2023. Any purchases will depend upon the cost competitiveness of the respective offers as well as other options available to Alabama Power. 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 –
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



"Credit Rating Risk," Note (B) to the Condensed Financial Statements herein.under "Regulatory Matters – Alabama Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air qualitylaws and water standards,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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.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.information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.
In 2014,2016, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard isASU No. 2016-02, which requires lessees to recognize revenue to depicton the transferbalance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosuresexpense associated with leases and provides clarification regarding the nature, amount, timing, and uncertaintyidentification of revenue and the related cash flows arising fromcertain components of contracts with customers.
While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements.that would represent a lease. The majority of Alabama Power's revenue, including energy provided to customers,accounting required by lessors is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Alabama Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.
The new standardrelatively unchanged. ASU 2016-02 is effective for interim and annual reporting periodsfiscal years beginning after December 15, 2017.2018 and Alabama Power intends to usewill adopt the modified retrospective method of adoptionnew standard effective January 1, 2018. 2019.
Alabama Power has also elected to utilize practical expedients which allowthe transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it towill apply the standard to open contracts atrequirements of ASU 2016-02 on a prospective basis as of the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



effect adjustment, is not expected to have a material impact on either the timing or amountadoption date of revenues recognized in Alabama Power's financial statements,January 1, 2019, without restating prior periods. Alabama Power willexpects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Alabama Power expects to evaluateapply the requirements,use-of-hindsight practical expedient in determining lease terms as wellof the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as any additional clarifying guidance that mayleases not to be issued.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Costreassessed. Alabama Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost componentto combine lease and non-lease components in the same line item or items as other compensation costscomputations of lease obligations and requiresright-of-use assets for most asset classes.
Alabama Power is continuing to complete the other componentsimplementation of net periodic pensionan information technology system to track and postretirement benefit costsaccount for its leases and of changes to be separately presented inits internal controls and accounting policies to support the income statement outside income from operations. Additionally, onlyaccounting for leases under ASU 2016-02. Alabama Power has substantially completed its lease inventory and determined its most significant leases involve PPAs. While Alabama Power has not yet determined the service cost componentultimate impact, adoption of ASU 2016-02 is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Alabama Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating incomerecording lease liabilities and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have aright-of-use assets on Alabama Power's balance sheet each totaling approximately $200 million, with no material impact on Alabama Power's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. Alabama Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoptionstatement of ASU 2017-12 is not expected to have a material impact on Alabama Power's financial statements.income.
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 September 30, 2017.2018. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.4$1.39 billion for the first nine months of 2017,2018, a decrease of $130$22 million as compared to the first nine months of 2016.2017. The decrease in net cash provided from operating activities was primarily due to the receipttiming of vendor payments partially offset by income tax refunds received in 2016 as a result of bonus depreciation.2018. Net cash used for investing activities totaled $1.2$1.60 billion for the first nine months of 20172018 primarily due to gross property additions related to environmental, distribution, environmental, transmission, and steam generation.assets. Net cash provided from financing activities totaled $339$369 million for the first nine months of 20172018 primarily due to an issuance of long-term debt and preferred stock and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a redemption of long-term debt.payments. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 20172018 include increases of $652 million$2.40 billion in property, plant, and equipment primarily due to increases in AROs related to the CCR Rule and additions to distribution, transmission, and steam generation, $548assets, $1.39 billion in AROs related to the CCR Rule and nuclear decommissioning, $504 million in additional paid-in capital primarily due to capital contributions from Southern Company, and $496 million in long-term debt primarily due to the issuancea senior note issuance. In addition, $321 million of additional senior notes, $533 million in cash and cash equivalents, $348 million in additional paid-in capital due to capital contributions from Southern Company, $265 million in
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the September 2017 issuance,long-term debt was reclassified as well as a decrease of $236 million in securities due within one year. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information related to changes in Alabama Power's AROs.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements.contractual obligations. Subsequent to September 30, 2017,2018, Alabama Power repaid at maturity $325purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series Q 5.50% Senior Notes due October 15, 2017. No2008. An additional funds$201 million will be required through September 30, 20182019 to fund maturities of long-term debt.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues"Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
In October 2018, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $2.2 billion for 2018, $1.6$1.8 billion for 2019, $1.6 billion for 2020, $1.7$1.6 billion for 2021, and $1.4 billion for 2022.2022, and $1.5 billion for 2023. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $0.6$0.3 billion for 2018,2019, $0.1 billion for 2019,2020, $0.2 billion for 2020, $0.32021, $0.2 billion for 2021,2022, and $0.3$0.1 billion for 2022.2023. These estimated expenditures do not include any potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limitassociated with pending regulation of CO2 emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units.
Alabama Power also anticipates costs associated with closure in placeclosure-in-place and monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule),CCR Rule, which are reflected in Alabama Power's asset retirement obligationARO liabilities. These costs, which are expected to change, could change materially as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities,activities. These costs are expected to begin in 2019 and are currently estimated to be $27 million for 2018, $101approximately $232 million for 2019, $105$238 million for 2020, $107$246 million for 2021, and $109$252 million for 2022.2022, and $258 million for 2023. See FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein, and 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 for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.
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 statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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, short-term debt, term loans, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See
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 September 30, 2017,2018, Alabama Power had approximately $953$702 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 20172018 were as follows:
ExpiresExpires     Expires Within One YearExpires     Expires Within One Year
2018 2020 2022 Total Unused Term Out No Term Out
20192019 2020 2022 Total Unused Term Out No Term Out
(in millions)
$35
 $500
 $800
 $1,335
 $1,335
 $—
 $35
33
 $500
 $800
 $1,333
 $1,333
 $—
 $33
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
In May 2017 and September 2017, Alabama Power amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.
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 September 30, 2017,2018, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $854 million as of September 30, 2017.2018. At September 30, 2017,2018, Alabama Power had no$120 million aggregate principal amount of fixed rate pollution control revenue bondsThe Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008 outstanding that were required to be reoffered within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held all of these bonds.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Short-term borrowings are included in notes payable in the balance sheets.
Details of commercial papershort-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 $30
 1.3% $220
 
Short-term Debt at
September 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$—
 —% $11
 2.2% $135
Short-term bank loan3
 3.7% 3
 3.7% 3
Total$3
 3.7% $14
 2.6%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 30, 2017.2018.
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At September 30, 2017,2018, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 30, 20172018 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and/or Baa2$1
$1
At BBB- and/or Baa3$2
$1
Below BBB- and/or Baa3$338
$284
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate company of Alabama Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&PSeptember 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Alabama Power).
Also on September 28, 2018, Moody's revised its consolidatedrating outlook for Alabama 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 outlook foragencies to assess Southern Company and its subsidiaries, (includingincluding Alabama Power) from stablePower, may be negatively impacted. The modifications to negative.Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power – Rate RSE" herein for additional information.
Financing Activities
In February 2017,June 2018, Alabama Power repaid at maturity $200issued $500 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45%2018A 4.30% Senior Notes due March 30, 2022.July 15, 2048. The proceeds were used to repay Alabama Power's short-term indebtednessoutstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.
In July 2017, Alabama Power repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2017,2018, Alabama Power repaid at maturity $325purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series Q 5.50% Senior Notes due October 15, 2017.2008. 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, 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.

Table of Contents

GEORGIA POWER COMPANYStorm Damage Recovery

See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
GEORGIA POWER COMPANYGeorgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.
CONDENSED STATEMENTS OF INCOME (UNAUDITED)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.
Storm Damage Cost Recovery
 For the Three Months Ended September 30, For the Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions) (in millions)
Operating Revenues:       
Retail revenues$2,402
 $2,540
 $5,995
 $6,164
Wholesale revenues, non-affiliates45
 49
 124
 131
Wholesale revenues, affiliates6
 9
 23
 24
Other revenues93
 100
 284
 302
Total operating revenues2,546
 2,698
 6,426
 6,621
Operating Expenses:       
Fuel482
 575
 1,297
 1,390
Purchased power, non-affiliates119
 102
 310
 277
Purchased power, affiliates161
 142
 470
 392
Other operations and maintenance413
 496
 1,194
 1,393
Depreciation and amortization225
 215
 669
 639
Taxes other than income taxes112
 114
 311
 311
Total operating expenses1,512
 1,644
 4,251
 4,402
Operating Income1,034
 1,054
 2,175
 2,219
Other Income and (Expense):       
Interest expense, net of amounts capitalized(105) (98) (310) (290)
Other income (expense), net5
 11
 41
 35
Total other income and (expense)(100) (87) (269) (255)
Earnings Before Income Taxes934
 967
 1,906
 1,964
Income taxes350
 363
 705
 734
Net Income584
 604
 1,201
 1,230
Dividends on Preferred and Preference Stock4
 4
 13
 13
Net Income After Dividends on Preferred and Preference Stock$580
 $600
 $1,188
 $1,217
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 For the Three Months Ended September 30, For the Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions) (in millions)
Net Income$584
 $604
 $1,201
 $1,230
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$585
 $605
 $1,203
 $1,232
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 accompanying notes as they relateGulf Power Tax Reform Settlement Agreement results in annual reductions to Georgia Power are an integral partGulf Power's revenues of these condensed financial statements.$18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided 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 September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the

GEORGIA POWERSOUTHERN COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months Ended September 30,
 2017 2016
 (in millions)
Operating Activities:   
Net income$1,201
 $1,230
Adjustments to reconcile net income to net cash provided from operating activities --   
Depreciation and amortization, total821
 794
Deferred income taxes328
 346
Allowance for equity funds used during construction(29) (36)
Deferred expenses(30) (40)
Pension, postretirement, and other employee benefits(42) (14)
Settlement of asset retirement obligations(95) (93)
Other, net(21) 7
Changes in certain current assets and liabilities —   
-Receivables(254) (162)
-Fossil fuel stock(2) 128
-Other current assets(29) 62
-Accounts payable(161) 39
-Accrued taxes(52) (22)
-Accrued compensation(60) (26)
-Retail fuel cost over recovery(84) 9
-Other current liabilities(11) 44
Net cash provided from operating activities1,480
 2,266
Investing Activities:   
Property additions(1,907) (1,566)
Nuclear decommissioning trust fund purchases(411) (563)
Nuclear decommissioning trust fund sales406
 558
Cost of removal, net of salvage(54) (45)
Change in construction payables, net of joint owner portion180
 (139)
Payments pursuant to LTSAs(59) (27)
Sale of property63
 10
Other investing activities(52) 14
Net cash used for investing activities(1,834) (1,758)
Financing Activities:   
Decrease in notes payable, net(391) (63)
Proceeds —   
Capital contributions from parent company412
 294
Senior notes1,350
 650
FFB loan—
 300
Short-term borrowings700
 —
Other long-term debt370
 —
Redemptions and repurchases —   
Pollution control revenue bonds(65) (4)
Senior notes(450) (700)
Short-term borrowings(300) —
Payment of common stock dividends(961) (979)
Other financing activities(48) (26)
Net cash provided from (used for) financing activities617
 (528)
Net Change in Cash and Cash Equivalents263
 (20)
Cash and Cash Equivalents at Beginning of Period3
 67
Cash and Cash Equivalents at End of Period$266
 $47
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $17 and $15 capitalized for 2017 and 2016, respectively)$284
 $277
Income taxes, net369
 188
Noncash transactions — Accrued property additions at end of period470
 226
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 September 30, 2017 At December 31, 2016
  (in millions)
Current Assets:    
Cash and cash equivalents $266
 $3
Receivables —    
Customer accounts receivable 670
 523
Unbilled revenues 276
 224
Under recovered fuel clause revenues 62
 —
Joint owner accounts receivable 222
 57
Other accounts and notes receivable 82
 81
Affiliated 21
 18
Accumulated provision for uncollectible accounts (3) (3)
Fossil fuel stock 300
 298
Materials and supplies 480
 479
Prepaid expenses 82
 105
Other regulatory assets, current 200
 193
Other current assets 27
 38
Total current assets 2,685
 2,016
Property, Plant, and Equipment:    
In service 34,589
 33,841
Less: Accumulated provision for depreciation 11,655
 11,317
Plant in service, net of depreciation 22,934
 22,524
Nuclear fuel, at amortized cost 551
 569
Construction work in progress 5,751
 4,939
Total property, plant, and equipment 29,236
 28,032
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 53
 60
Nuclear decommissioning trusts, at fair value 914
 814
Miscellaneous property and investments 51
 46
Total other property and investments 1,018
 920
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 669
 676
Other regulatory assets, deferred 2,890
 2,774
Other deferred charges and assets 608
 417
Total deferred charges and other assets 4,167
 3,867
Total Assets $37,106
 $34,835
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 September 30, 2017 At December 31, 2016
  (in millions)
Current Liabilities:    
Securities due within one year $261
 $460
Notes payable 400
 391
Accounts payable —    
Affiliated 396
 438
Other 1,012
 589
Customer deposits 270
 265
Accrued taxes 353
 407
Accrued interest 121
 106
Accrued compensation 164
 224
Asset retirement obligations, current 214
 299
Other current liabilities 192
 297
Total current liabilities 3,383
 3,476
Long-term Debt 11,610
 10,225
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 6,328
 6,000
Accumulated deferred ITCs 248
 256
Employee benefit obligations 665
 703
Asset retirement obligations, deferred 2,367
 2,233
Other deferred credits and liabilities 232
 320
Total deferred credits and other liabilities 9,840
 9,512
Total Liabilities 24,833
 23,213
Preferred Stock 45
 45
Preference Stock 221
 221
Common Stockholder's Equity:    
Common stock, without par value —    
Authorized — 20,000,000 shares    
Outstanding — 9,261,500 shares 398
 398
Paid-in capital 7,308
 6,885
Retained earnings 4,311
 4,086
Accumulated other comprehensive loss (10) (13)
Total common stockholder's equity 12,007
 11,356
Total Liabilities and Stockholder's Equity $37,106
 $34,835
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
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 became effective with 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 certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through a separate Mississippi Power cost rider. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation 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 is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $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 45% at September 30, 2018) to 50% by December 31, 2018. 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 are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2017 vs. THIRD QUARTER 2016The 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.
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016


OVERVIEW
Georgia Power operatesOn 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 vertically integrated utility providing electric service to retail customers within its traditional service territory located withinresult of the StateTax Reform Legislation. The resulting decrease of Georgiaapproximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and to wholesale customersROE of 9.8% were not addressed in the Southeast.rehearing and remain unchanged.
Many factors affectKemper County Energy Facility
For additional information on the opportunities, challenges,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 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. GeorgiaMississippi Power has various regulatory mechanisms that operatea contractual obligation to address cost recovery. Effectively operating pursuantfund all reclamation activities. Mine reclamation began in the first quarter 2018.
As of September 30, 2018, Mississippi Power recorded charges to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Powerincome of an immaterial amount for the foreseeable future.
Georgia Power continuesthird quarter 2018 and $45 million ($34 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 focus on several key performance indicatorscost up to $20 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, customer satisfaction, plant availability,costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-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 executionevent the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and net income after dividends on preferredacquires 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 preference stock.meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 3 and 12 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Southern Power – Construction Projects in Progress," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Nuclear Construction
Georgia Power andThe largest construction project currently underway in the Vogtle Owners have been constructingSouthern Company system is Plant Vogtle Units 3 and 4 since 2009. On March 29, 2017,(45.7% ownership interest by Georgia Power in the EPC Contractortwo units, each with approximately 1,100 MWs). See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work,
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreementthe Interim Assessment Agreement with the EPC Contractor (Interimto allow construction to continue. The Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9,Agreement expired in July 2017 Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.
Additionally, on June 9, 2017,when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 27, 2017,Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and the EPC Contractor's rejection of theengineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle 3 and 4 Agreement, became effective upon approval by the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 isare 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. Effective
In October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered intoexecuted the Bechtel Agreement, a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel),cost reimbursable plus fee arrangement, whereby Bechtel will serve asis 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 primary contractorBechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for the remaining construction activities for Plant Vogtle Units 3 and 4.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believestheir convenience, provided that the most reasonable schedule for completing Plant Vogtle Units 3Owners 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
GEORGIA POWERSOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2018(b)
(4.3)
Remaining estimate to complete(a)
$4.1
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.
The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted 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 did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.
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 only recently began initial operation in the global nuclear industry at this scale); or other
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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 Criteria (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 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 August 31, 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 as described above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 20212022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC 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, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
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 Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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 expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.
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 November 2022 for Unit 4, at an additionalGeorgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of approximately $1.41$7.3 billion net(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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 to 2022.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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.
The Georgia PSC is expected to make a decision onhas approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 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.
The ultimate outcome of these matters by February 6, 2018.cannot be determined at this time.
OnSee RISK FACTORS of Southern Company in Item 1A herein and 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
As of September 28,30, 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 September 2018, the DOE extended the conditional commitment to March 31, 2019. 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. See Note 6 to the financial statements of Georgia PowerSouthern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "DOE"DOE Loan Guarantee Borrowings"Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
An inability See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Southern Power
In April 2018, Southern Power completed the final stage of 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 $54 million, which were recorded in the first half of 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or other failure by Toshibarequests 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 perform its obligations under the Guarantee Settlement Agreement couldCondensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a furthermaterial effect on Southern Company's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On October 2, 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings.
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 netMississippi 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 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. On August 10, 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On May 4, 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.
On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Investments in Leveraged Leases
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Investments in Leveraged Leases" of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) 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 September 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 September 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle OwnersUnits 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 completecontinue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and therefore,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 financial statements. total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds) 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 approximately $188 million in related Customer Refunds). 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 did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast in the nineteenth VCM report filed with the Georgia PSC 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 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 only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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. 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

estimates. 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 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) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
The Southern Company system is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. The Southern Company system has substantially completed its lease inventory and determined its most significant leases involve PPAs, real estate, and communication towers where certain of Southern Company's subsidiaries are the lessee and PPAs where certain of Southern Company's subsidiaries are the lessor. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company's balance sheet each totaling approximately $2.1 billion, with no material impact on Southern Company's statement of income.
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 September 30, 2018. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $5.6 billion for the first nine months of 2018, an increase of $0.3 billion from the corresponding period in 2017. The increase in net cash provided from operating activities was primarily due to increased fuel cost recovery and the timing of vendor payments. Net cash used for investing activities totaled $3.5 billion for the first nine months of 2018 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the Southern Company Gas Dispositions. Net cash used for financing activities totaled $2.3 billion for the first nine months of 2018 primarily due to net redemptions and repurchases of long-term debt, common stock dividend payments, and a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities, and the issuance of common stock. 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 nine months of 2018 include the reclassification of $5.1 billion and $3.2 billion in total assets and liabilities held for sale, respectively, primarily associated with Gulf Power, as well as decreases of $2.8 billion and $0.4 billion in total assets and liabilities, respectively, associated with the Southern Company Gas Dispositions. See Note (J) to the Condensed Financial Statements under "Assets Held for Sale" and "Southern Company Gas" herein for additional information. After adjusting for these changes, other significant balance sheet changes include an increase of $4.0 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 second quarter 2018 charge related to the construction of Plant Vogtle Units 3 and 4; a decrease of $2.6 billion in long-term debt (including amounts due within one year) resulting from the repayment of long-term debt; an increase of $1.8 billion in noncontrolling interests primarily related to Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities; and an increase of $1.5 billion in ARO liabilities primarily related to revised estimates for ash pond closure costs at Alabama Power to comply with the CCR Rule. See Notes (A), (B), (F), and (J) to the Condensed Financial Statements under "Asset Retirement Obligations," "Nuclear Construction," "Financing Activities," and "Southern Power – Sale of Solar Facility Interests," respectively, herein for additional information.
At the end of the third quarter 2018, the market price of Southern Company's common stock was $43.60 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $24.18 per share, representing a market-to-book ratio of 180%, compared to $48.09, $23.99, and 201%, respectively, at the end of 2017. Southern Company's common stock dividend for the third quarter 2018 was $0.60 per share compared to $0.58 per share in the third quarter 2017.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements and contractual obligations. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019, Alabama Power purchased and held $120 million of pollution control revenue bonds, and Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $2.6 billion will be required through September 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The Southern Company system's construction program is currently estimated to total approximately $8.8 billion for 2018, $8.2 billion for 2019, $7.2 billion for 2020, $7.0 billion for 2021, and $6.7 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $0.5 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, as revised subsequent to Tax Reform Legislation. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and costs, which are immaterial to Southern Company, relating to assets divested during 2018 and held for sale at September 30, 2018. Estimated capital expenditures to comply with environmental laws and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 pending 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 fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Retail Regulatory MattersAsset Retirement Obligations" herein. Also see Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Southern Company also plans to utilize the proceeds from the disposition of Gulf Power when completed for future capital needs. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on March 31, 2019, 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. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's cost-to-complete and cancellation cost assessments forregarding 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 September 30, 2018, Southern Company's current liabilities exceeded current assets by $3.6 billion due to long-term debt that is due within one year of $3.0 billion (including approximately $1.3 billion at the parent company, $0.3 billion at Alabama Power, $0.5 billion at Georgia Power, $0.2 billion at Mississippi Power, and $0.5 billion at Southern Company Gas) and notes payable of $2.6 billion (including approximately $2.0 billion at the parent company, $0.1 billion at Georgia Power, $0.1 billion at Gulf Power, $0.2 billion at Southern Power, and $0.1 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net Income
At September 30, 2018, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(20) (3.3) $(29) (2.4)
 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 Power—
33
500
800
 1,333
 1,333
 —
 —
 33
Georgia Power—
—
—
1,750
 1,750
 1,736
 —
 —
 —
Gulf Power20
25
235
—
 280
 280
 45
 45
 —
Mississippi Power—
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$20
$188
$735
$7,200
 $8,143
 $8,101
 $45
 $45
 $63
(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 2019, of which $22 million remains unused at September 30, 2018.
(c)
Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, and Southern Power Company contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. All but $40 million of the bank credit arrangements do not contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2018 was approximately $1.5 billion. In addition, at September 30, 2018, the traditional electric operating companies had approximately $573 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held approximately $120 million of its outstanding pollution control revenue bonds required to be remarketed.
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), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
  
Short-term Debt at
September 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 $611
 2.5% $1,323
 2.4% $3,008
Short-term bank debt 1,953
 2.9% 1,790
 3.0% 2,003
Total $2,564
 2.8% $3,113
 2.7%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At September 30, 2018, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2018 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$38
At BBB- and/or Baa3$578
At BB+ and/or Ba1(*)
$2,120
(*)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 August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.
On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Also 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's net income after dividendsPower to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A.
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.
On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3.
On September 28, 2018, Moody's revised its rating outlooks for Southern Company, Alabama Power, and Georgia Power from negative to stable.
Also on preferredSeptember 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and preferenceits subsidiaries (excluding Gulf Power and Mississippi Power).
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 3 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including 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 nine months of 2018, Southern Company issued approximately 9.2 million shares of common stock forprimarily through employee equity compensation plans and received proceeds of approximately $338 million.
In addition, during the third quarter 2017 was $5802018, Southern Company issued a total of approximately 12.1 million comparedshares of common stock through at-the-market issuances pursuant to $600sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $540 million, net of approximately $5 million in commissions. Subsequent to September 30, 2018, Southern Company issued an additional approximately 2.5 million shares of common stock through at-the-market issuances and received cash proceeds of approximately $107 million, net of approximately $1 million in commissions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the corresponding period in 2016. For year-to-date 2017, net income after dividends on preferred and preference stock was $1.19 billion compared to $1.22 billion for the corresponding period in 2016. The decreases were primarily due to lower revenues resulting from milder weather and lower customer usage as compared to the corresponding periods in 2016, partially offset by lower non-fuel operations and maintenance expenses.
Retail Revenuesfirst nine months of 2018:
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(138) (5.4) $(169) (2.7)
Company
Senior
Note
Issuances
 Senior Note Maturities, Redemptions, and Repurchases 
Revenue Bond
Maturities, Redemptions, and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other Long-Term Debt Redemptions
and Maturities(a)
 (in millions)
Southern Company(b)
$750
 $1,000
 $—
 $—
 $—
Alabama Power500
 —
 —
 —
 —
Georgia Power—
 1,000
 469
 —
 107
Mississippi Power600
 —
 43
 —
 900
Southern Power—
 350
 —
 —
 420
Southern Company Gas—
 —
 200
 100
 —
Other—
 —
 —
 —
 10
Elimination(c)
—
 —
 —
 —
 (1)
Southern Company Consolidated$1,850
 $2,350
 $712
 $100
 $1,436
(a)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(b)Represents the Southern Company parent entity.
(c)Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's Consolidated Financial Statements.
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 March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.
In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on no less than 30 days' demand by the bank.
In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.
In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to a short-term uncommitted bank credit arrangement.
In the third quarter 2017, retail revenues2018, Southern Company repaid at maturity $500 million aggregate principal amount of 1.55% Senior Notes and $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes.
Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. These bonds may be remarketed to the public in the future.
In January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.
In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.
In March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. The proceeds of this loan, together with the proceeds of Mississippi Power's $600 million senior notes issuances, were $2.40 billion comparedused to $2.54 billionrepay Mississippi Power's $900 million unsecured floating rate term loan.
Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.
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.
During the correspondingnine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to certain of its renewable facilities. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.
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 repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.
In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in November 2018.
Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.
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.

Table of Contents

PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2018, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (D) and Note (I) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in 2016. For year-to-date 2017, retail revenues were $6.00 billion comparedSections 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 third quarter 2018 that have materially affected or are reasonably likely to $6.16 billion for the corresponding period in 2016.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.

GEORGIATable of Contents

ALABAMA POWER COMPANY

Table of Contents

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Operating Revenues:       
Retail revenues$1,584
 $1,595
 $4,208
 $4,155
Wholesale revenues, non-affiliates74
 77
 213
 210
Wholesale revenues, affiliates14
 18
 96
 83
Other revenues68
 50
 199
 158
Total operating revenues1,740
 1,740
 4,716
 4,606
Operating Expenses:       
Fuel356
 343
 1,028
 944
Purchased power, non-affiliates64
 57
 176
 132
Purchased power, affiliates69
 55
 149
 117
Other operations and maintenance401
 406
 1,191
 1,177
Depreciation and amortization192
 185
 570
 549
Taxes other than income taxes97
 93
 289
 284
Total operating expenses1,179
 1,139
 3,403
 3,203
Operating Income561
 601
 1,313
 1,403
Other Income and (Expense):       
Allowance for equity funds used during construction16
 11
 43
 27
Interest expense, net of amounts capitalized(82) (76) (240) (229)
Other income (expense), net9
 10
 24
 35
Total other income and (expense)(57) (55) (173) (167)
Earnings Before Income Taxes504
 546
 1,140
 1,236
Income taxes127
 216
 272
 493
Net Income377
 330
 868
 743
Dividends on Preferred and Preference Stock4
 5
 11
 14
Net Income After Dividends on Preferred and Preference Stock$373
 $325
 $857
 $729

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income$377
 $330
 $868
 $743
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $1, and $2, respectively		1
 1
 3
 3
Total other comprehensive income (loss)1
 1
 3
 3
Comprehensive Income$378
 $331
 $871
 $746
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

Table of Contents

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$868
 $743
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total683
 666
Deferred income taxes104
 260
Allowance for equity funds used during construction(43) (27)
Settlement of asset retirement obligations(31) (20)
Other, net(6) 59
Changes in certain current assets and liabilities —   
-Receivables(207) (163)
-Prepayments(26) (28)
-Materials and supplies(69) (29)
-Other current assets66
 33
-Accounts payable(194) (125)
-Accrued taxes225
 159
-Accrued compensation(41) (48)
-Retail fuel cost over recovery—
 (76)
-Other current liabilities60
 7
Net cash provided from operating activities1,389
 1,411
Investing Activities:   
Property additions(1,529) (1,211)
Nuclear decommissioning trust fund purchases(207) (174)
Nuclear decommissioning trust fund sales207
 174
Cost of removal, net of salvage(78) (82)
Change in construction payables30
 105
Other investing activities(23) (29)
Net cash used for investing activities(1,600) (1,217)
Financing Activities:   
Proceeds —   
Senior notes500
 550
Capital contributions from parent company495
 337
Preferred stock—
 250
Redemptions —   
Senior notes—
 (200)
Pollution control revenue bonds—
 (36)
Payment of common stock dividends(602) (536)
Other financing activities(24) (26)
Net cash provided from financing activities369
 339
Net Change in Cash, Cash Equivalents, and Restricted Cash158
 533
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period544
 420
Cash, Cash Equivalents, and Restricted Cash at End of Period$702
 $953
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $15 and $10 capitalized for 2018 and 2017, respectively)$220
 $217
Income taxes, net30
 146
Noncash transactions — Accrued property additions at end of period275
 189
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

Table of Contents

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $702
 $544
Receivables —    
Customer accounts receivable 455
 355
Unbilled revenues 159
 162
Under recovered regulatory clause revenues 48
 —
Affiliated 68
 43
Other accounts and notes receivable 54
 55
Accumulated provision for uncollectible accounts (9) (9)
Fossil fuel stock 117
 184
Materials and supplies 536
 458
Prepaid expenses 59
 85
Other regulatory assets, current 141
 124
Other current assets 8
 5
Total current assets 2,338
 2,006
Property, Plant, and Equipment:    
In service 29,568
 27,326
Less: Accumulated provision for depreciation 9,932
 9,563
Plant in service, net of depreciation 19,636
 17,763
Nuclear fuel, at amortized cost 316
 339
Construction work in progress 1,457
 908
Total property, plant, and equipment 21,409
 19,010
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 63
 67
Nuclear decommissioning trusts, at fair value 938
 903
Miscellaneous property and investments 127
 124
Total other property and investments 1,128
 1,094
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 236
 239
Deferred under recovered regulatory clause revenues 88
 54
Other regulatory assets, deferred 1,209
 1,272
Other deferred charges and assets 202
 189
Total deferred charges and other assets 1,735
 1,754
Total Assets $26,610
 $23,864
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


Table of Contents

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At September 30, 2018 At December 31, 2017
  (in millions)
Current Liabilities:    
Securities due within one year $321
 $—
Accounts payable —    
Affiliated 341
 327
Other 425
 585
Customer deposits 96
 92
Accrued taxes —    
Accrued income taxes 97
 9
Other accrued taxes 132
 45
Accrued interest 81
 77
Accrued compensation 169
 205
Asset retirement obligations, current 111
 7
Other regulatory liabilities, current 57
 1
Other current liabilities 46
 52
Total current liabilities 1,876
 1,400
Long-term Debt 7,803
 7,628
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 2,882
 2,760
Deferred credits related to income taxes 2,051
 2,082
Accumulated deferred ITCs 107
 112
Employee benefit obligations 283
 304
Asset retirement obligations 3,090
 1,702
Other cost of removal obligations 542
 609
Other regulatory liabilities, deferred 52
 84
Other deferred credits and liabilities 48
 63
Total deferred credits and other liabilities 9,055
 7,716
Total Liabilities 18,734
 16,744
Redeemable Preferred Stock 291
 291
Common Stockholder's Equity:    
Common stock, par value $40 per share —    
Authorized — 40,000,000 shares    
Outstanding — 30,537,500 shares 1,222
 1,222
Paid-in capital 3,490
 2,986
Retained earnings 2,902
 2,647
Accumulated other comprehensive loss (29) (26)
Total common stockholder's equity 7,585
 6,829
Total Liabilities and Stockholder's Equity $26,610
 $23,864
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



DetailsTHIRD QUARTER 2018 vs. THIRD QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the changesForm 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
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)
(% change)
(change in millions)
(% change)
$48 14.8 $128 17.6
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2018 was $373 million compared to $325 million for the corresponding period in 2017. Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2018 was $857 million compared to $729 million for the corresponding period in 2017. These increases were primarily related to an increase in retail revenues were as follows:
 Third Quarter 2017 Year-to-Date 2017
 (in millions) (% change) (in millions) (% change)
Retail – prior year$2,540
   $6,164
  
Estimated change resulting from –       
Rates and pricing41
 1.6
 60
 1.0
Sales decline(39) (1.5) (50) (0.8)
Weather(94) (3.7) (204) (3.3)
Fuel cost recovery(46) (1.8) 25
 0.4
Retail – current year$2,402
 (5.4)% $5,995
 (2.7)%
Revenues associated with changes in rates and pricing increasedcolder weather in the first quarter 2018 and warmer weather in the second and third quarter and year-to-date 2017 whenquarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2016 primarily due to an increase2017 and a decrease in revenuesincome tax expense, partially offset by customer bill credits related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff.Tax Reform Legislation. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Nuclear Construction" of Georgia PowerRate RSE" in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information related to the NCCR tariff.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 3.5% and 0.8% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage due to an increase in multi-family housing and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions, partially offset by customer growth. Weather-adjusted industrial KWH sales increased 0.8% in the third quarter 2017 primarily due to increased demand in the non-manufacturing, rubber, and textile sectors, partially offset by decreased demand in the chemicals and paper sectors. Weather-adjusted industrial KWH sales decreased 1.2% for year-to-date 2017 primarily due to decreased demand in the paper and chemicals sectors, partially offset by increased demand in the non-manufacturing and rubber sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes during the third quarter and year-to-date 2017.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. In the third quarter 2017, retail fuel cost recovery revenues decreased $46 million when compared to the corresponding period in 2016 primarily due to lower coal prices and lower energy sales resulting from milder weather. For year-to-date 2017, retail fuel cost recovery revenues increased $25 million when compared to the corresponding period in 2016 primarily due to higher natural gas prices, partially offset by lower coal prices and lower energy sales resulting from milder weather. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 78 of the Form 10-K for additional information.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



OtherRetail Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(7) (7.0) $(18) (6.0)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(11) (0.7) $53 1.3
In the third quarter 2017, other2018, retail revenues were $93$1.58 billion compared to $1.60 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $4.21 billion compared to $4.16 billion for the corresponding period in 2017.
Details of the changes in retail revenues were as follows:
 Third Quarter 2018
Year-to-Date 2018
 (in millions)
(% change)
(in millions)
(% change)
Retail – prior year$1,595
   $4,155
  
Estimated change resulting from –       
Rates and pricing(87) (5.5) (195) (4.7)
Sales decline(2) (0.1) (8) (0.1)
Weather37
 2.3
 130
 3.1
Fuel and other cost recovery41
 2.6
 126
 3.0
Retail – current year$1,584
 (0.7)% $4,208
 1.3%
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to customer bill credits related to the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted commercial KWH sales decreased 1.1% and 1.4% for the third quarter and year-to-date 2018, respectively, and weather-adjusted residential KWH sales decreased 0.3% and 0.5% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to lower customer usage related to energy efficiency. Industrial KWH sales increased 1.3% and 2.4% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, and in the pipelines sector, partially offset by a decrease in demand in the paper and chemicals sectors, primarily due to customer maintenance outages and on-site cogeneration.
Revenues resulting from changes in weather increased in the third quarter and year-to-date 2018 due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2017. For the third quarter 2018, the resulting increases were 3.9% and 2.2% for residential and commercial sales revenues, respectively. For year-to-date 2018, the resulting increases were 5.7% and 2.3% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to increases in KWH generation and the average cost of fuel.
Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Wholesale Revenues – Affiliates
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(4) (22.2) $13 15.7
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
For year-to-date 2018, wholesale revenues from sales to affiliates were $96 million compared to $100$83 million for the corresponding period in 2016.2017. The decreaseincrease was primarily due to a $312% increase in the price of energy and a 3% increase in KWH sales as a result of increased demand due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$18 36.0 $41 25.9
In the third quarter 2018, other revenues were $68 million decreasecompared to $50 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $199 million compared to $158 million for the corresponding period in 2017. These increases were primarily due to revenues related to unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606. The year-to-date 2018 increase was partially offset by decreases in open access transmission tariff revenues primarily as a result of the expiration of long-term transmission services contracts,due to expected declines in customers' needs and a $3 million decrease in solar application fee revenues, partially offset by a $3 million increase in outdoor lighting sales revenues primarily attributablelower rate related to LED conversions.
For year-to-date 2017, other revenues were $284 million compared to $302 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenues and a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.Tax Reform Legislation.
Fuel and Purchased Power Expenses
Third Quarter 2017
vs.
Third Quarter 2016		 Year-to-Date 2017
vs.
Year-to-Date 2016		Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)(change in millions)
(% change) (change in millions) (% change)
Fuel$(93) (16.2) $(93) (6.7)$13
 3.8 $84
 8.9
Purchased power – non-affiliates17
 16.7
 33
 11.9
7
 12.3 44
 33.3
Purchased power – affiliates19
 13.4
 78
 19.9
14
 25.5 32
 27.4
Total fuel and purchased power expenses$(57)   $18
  $34
 $160
 
In the third quarter 2017, total2018, fuel and purchased power expenses were $762$489 million compared to $819$455 million infor the corresponding period in 2016. The decrease was primarily due to a $59 million decrease related to the volume of KWHs generated primarily due to milder weather, resulting in lower customer demand, and slight decreases in the volume of KWHs purchased and the average cost of fuel. These decreases were partially offset by a $7 million increase in the average cost of purchased power primarily related to higher natural gas prices.
For year-to-date 2017, total fuel and purchased power expenses were $2.08 billion compared to $2.06 billion in the corresponding period in 2016.2017. The increase was primarily due to a $97$23 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, partially offset by a net decrease of $79 million related to the volume of KWHs generated and purchased and a $16 million increase related to the average cost of fuel, partially offset by a $5 million decrease in the average cost of purchased power.
For year-to-date 2018, fuel and purchased power expenses were $1.35 billion compared to $1.19 billion for the corresponding period in 2017. The increase was primarily due to milder weather, resultinga $98 million increase related to the volume of KWHs generated and purchased and a $32 million increase related to the average cost of fuel.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In addition, fuel expense increased $30 million year-to-date 2018 in lower customer demand.accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuelenergy expenses are generally offset by fuelenergy revenues through GeorgiaAlabama Power's fuelenergy cost recovery mechanism.clause. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL –Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia PowerRate ECR" in Item 78 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Details of GeorgiaAlabama Power's generation and purchased power were as follows:
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018
Year-to-Date 2017
Total generation (in billions of KWHs)
18 20 48 5316 16 47 46
Total purchased power (in billions of KWHs)
7 7 20 193 2 6 5
Sources of generation (percent) —
  
Coal35 44 33 3754 52 52 49
Nuclear23 22 24 2324 24 22 25
Gas41 34 41 3818 19 19 20
Hydro1 — 2 24 5 7 6
Cost of fuel, generated (in cents per net KWH) —
 
Cost of fuel, generated (in cents per net KWH)(a) —
 
Coal3.08 3.16 3.17 3.322.74 2.61 2.74 2.61
Nuclear0.84 0.85 0.84 0.850.78 0.75 0.77 0.75
Gas2.63 2.61 2.71 2.272.80 2.72 2.72 2.74
Average cost of fuel, generated (in cents per net KWH)(b)
2.38 2.47 2.40 2.342.27 2.17 2.27 2.15
Average cost of purchased power (in cents per net KWH)(*)
4.68 4.57 4.63 4.46
Average cost of purchased power (in cents per net KWH)(c)
5.43 5.65 5.59 5.57
(*)(a)Cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment for year-to-date 2018 associated with the Alabama PSC accounting order related to excess deferred income taxes.
(b)KWHs generated by hydro are excluded from the average cost of fuel, generated.
(c)Average cost of purchased power includes fuel, energy, and transmission purchased by GeorgiaAlabama Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2017,2018, fuel expense was $482$356 million compared to $575$343 million infor the corresponding period in 2016.2017. The decreaseincrease was primarily due to a 9.6%16.6% decrease in the volume of KWHs generated largelyby hydro facilities due to milder weather, resulting in lower customer demand, andrainfall, a 3.6% decrease5.0% increase in the average cost of coal per KWH generated, a 4.0% increase in the average cost of nuclear fuel per KWH generated, primarily resulting from lower coal prices.
For year-to-date 2017, fuel expense was $1.30 billion compared to $1.39 billionand a 3.9% decrease in the corresponding period in 2016. The decrease was primarilyvolume of KWHs generated by nuclear facilities due to the timing of outages. In addition, the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, increased 2.9% and the volume of KWHs generated by coal increased 2.0%. These increases were partially offset by an 8.4% decrease in the volume of KWHs generated largelyby natural gas.
For year-to-date 2018, fuel expense was $1.03 billion compared to $944 million for the corresponding period in 2017. The increase was primarily due to milder weather, resultinga 10.8% decrease in lower customer demand, partially offsetthe volume of KWHs generated by nuclear facilities due to outages, a 19.4%6.9% increase in the volume of KWHs generated by coal, and a 5.0% increase in the average cost of natural gascoal per KWH generated. These increases were partially offset by an 11.7% increase in the volume of KWHs generated by hydro facilities due to the timing of rainfall and a 4.1% decrease in the volume of KWHs generated by natural gas.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In addition, fuel expense increased $30 million year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.
Purchased Power – Non-Affiliates
In the third quarter 2017,2018, purchased power expense from non-affiliates was $119$64 million compared to $102$57 million infor the corresponding period in 2016. 2017. The increase was primarily related to a 14.8% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2017,2018, purchased power expense from non-affiliates was $310$176 million compared to $277$132 million infor the corresponding period in 2016.2017. The increases wereincrease was primarily duerelated to increasesa 24.3% increase in the volumeamount of KWHsenergy purchased of 14.2% and 12.6% in the third quarter and year-to-date 2017, respectively, primarily due to unplanned outages at Georgia Power-owned generating units. Thea 6.7% increase for year-to-date 2017 was partially offset by a 1.5% decrease in the average cost of purchased power per KWH purchased.due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2017,2018, purchased power expense from affiliates was $161$69 million compared to $142$55 million infor the corresponding period in 2016.2017. The increase was primarily duerelated to a 1.5%28% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 5.6% decrease in the volumeamount of
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


KWHs energy purchased due to warmer weather in the expiration of a PPAthird quarter 2018 compared to the corresponding period in May 2017 and milder weather, resulting in lower customer demand.2017.
For year-to-date 2017,2018, purchased power expense from affiliates was $470$149 million compared to $392$117 million infor the corresponding period in 2016.2017. The increase was primarily the result ofrelated to a 4.3%35% increase in the volumeamount of KWHsenergy purchased to support Southern Company system transmission reliability and due to unplanned outages at Georgia Power-owned generating units andas a 5.9% increaseresult of colder weather in the average cost per KWH purchased primarily resulting from higher natural gas prices.first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(83) (16.7) $(199) (14.3)
In the third quarter 2017, other operations and maintenance expenses were $413 million compared to $496 million in the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $29 million in generation maintenance costs, $9 million in customer accounts, service, and sales costs, $8 million in employee benefits, and $8 million in transmission and distribution overhead line maintenance. Other factors include decreases of $12 million in charges related to employee attrition plans and $8 million in scheduled generation outage costs.
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(5) (1.2) $14 1.2
For year-to-date 2017,2018, other operations and maintenance expenses were $1.19 billion compared to $1.39$1.18 billion infor the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $56 million in generation maintenance costs, $34 million in other employee compensation and benefits, and $23 million in transmission and distribution overhead line maintenance. Other factors include a $19 million increase in gains from sales of integrated transmission system assets, a $16 million decrease in customer assistance expenses primarily in demand-side management costs related to the timing of new programs, an $8 million decrease in charges related to employee attrition plans, and a $7 million decrease in billing adjustments with integrated transmission system owners.
Depreciation and Amortization
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$10 4.7 $30 4.7
In the third quarter 2017, depreciation and amortization was $225 million compared to $215 million in the corresponding period in 2016.2017. The increase was primarily due to an $8$33 million increase related to additional plantof 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 service and a $4other income (expense), net. In addition, distribution costs increased $29 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016.
For year-to-date 2017, depreciation and amortization was $669 million compared to $639 million in the corresponding period in 2016. The increase was primarily due to a $25 million increase related to additional plant in service and an $11 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016,line maintenance. These increases were partially offset by a $5$23 million decrease in depreciation relatedsteam generation costs primarily due to generating unit retirementsthe timing of outages, an $8 million decrease in 2016.employee benefits as a result of amounts capitalized in connection with an increase in construction projects, a $7 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects, and a $6 million decrease in property insurance primarily due to the receipt of refunds.
GEORGIASee Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 3.8 $21 3.8
In the third quarter 2018, depreciation and amortization was $192 million compared to $185 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $570 million compared to $549 million for the corresponding period in 2017. These increases were primarily due to additional plant in service related to steam generation, transmission, and distribution assets. See Note 1 to the financial statements of Alabama Power under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$5 45.5 $16 59.3
In the third quarter 2018, AFUDC equity was $16 million compared to $11 million for the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $43 million compared to $27 million for the corresponding period in 2017. These increases were primarily due to an increase in capital expenditures related to environmental and transmission projects.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$7 7.1 $20 6.9
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 7.9 $11 4.8
In the third quarter 2017,2018, interest expense, net of amounts capitalized was $105$82 million compared to $98$76 million infor the corresponding period in 2016.2017. For year-to-date 2017,2018, interest expense, net of amounts capitalized was $310$240 million compared to $290$229 million infor the corresponding period in 2016. The2017. These increases were primarily due to increasesan increase in the average debt outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information.higher interest rates, partially offset by an increase in the amounts capitalized.
Other Income (Expense), Net
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
Third Quarter 2018 vs. Third Quarter 2017Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change) (% change) (change in millions) (% change)
$(6)(1) (54.5) $6 17.1 (10.0) $(11) (31.4)
For year-to-date 2018, other income (expense), net was $24 million compared to $35 million for the corresponding period in 2017. This decrease was 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Income Taxes
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(89) (41.2) $(221) (44.8)
In the third quarter 2017, other2018, income (expense), net was $5taxes were $127 million compared to $11$216 million infor the corresponding period in 2016. The decrease was primarily due to a decrease of $9 million in AFUDC equity resulting from higher short-term borrowings, partially offset by increases of $3 million in customer contributions in aid of construction and $3 million in contract services revenue.
2017. For year-to-date 2017, other2018, income (expense), net was $41taxes were $272 million compared to $35$493 million infor the corresponding period in 2016. The increase was primarily due to increases of $6 million in contract services revenue, $4 million in customer contributions in aid of construction, and $4 million in gains on purchases of state tax credits, partially offset by a $7 million decrease in AFUDC equity resulting from higher short-term borrowings.
Income Taxes
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(13) (3.6) $(29) (4.0)
In the third quarter 2017, income taxes were $350 million compared to $363 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $705 million compared to $734 million in the corresponding period in 2016. The2017. 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 earningsearnings. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" and increased state ITCs.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 GeorgiaAlabama Power's future earnings potential. The level of GeorgiaAlabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of GeorgiaAlabama Power's primary business of providing electric service. These factors include GeorgiaAlabama 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. Matters related to Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Future earnings will be driven primarilyimpacted by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, and higher multi-family home construction.both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in GeorgiaAlabama Power's service territory. Demand for electricity is primarily driven by the pace of economic
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Georgia Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of GeorgiaAlabama Power in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.10-K.
Environmental Matters
ComplianceAlabama 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 relatedassociated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to federal and statecomply with environmental statuteslaws 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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed.recovered through Rate CNP Compliance. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 GeorgiaAlabama Power in Item 7 and Note 3 to the financial statements of GeorgiaAlabama Power under "Environmental Matters" and "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Environmental StatutesLaws and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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 October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Alabama Power is evaluating the extent of potential impacts on legacy units. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
On April 20, 2018, the Alabama Environmental Management Commission approved a state CCR rule that has been provided to the EPA for a six-month review period. This state CCR rule is generally consistent with the federal CCR Rule. The ultimate outcome of this matter cannot be determined at this time.
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As further analysis is performed and closure details are developed with respect to ash pond closures, Alabama Power expects to periodically update these cost estimates. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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.
Nuclear Decommissioning
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.
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.
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.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Alabama Power has ownership interests in 20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Alabama Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
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 – "Environmental Matters – Environmental Statutes and Regulations – Air Quality""FERC Matters" of GeorgiaAlabama Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the EPA's eight-hour ozone National Ambient Air Quality Standard (NAAQS).traditional electric operating companies' (including Alabama Power's) and Southern Power's 2014 and 2017 triennial market power analyses.
On June 2, 2017,May 4, 2018, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainmentFERC 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 2008 eight-hour ozone NAAQS.
On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extensiontraditional electric operating companies (including Alabama Power) and reinstated the original October 1, 2017 designation deadline. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of GeorgiaSouthern Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay ofmade the compliance deadlines for certain effluent limitations and pretreatment standards underfiling required by the rule.order. These proceedings are concluded.
GEORGIAALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 27, 2017, the EPA18, 2018, SCS and the U.S. Army Corps of Engineers proposed to rescindtraditional electric operating companies (including Alabama Power) filed their response challenging the final rule that revised the regulatory definition of watersadequacy of the U.S.showing presented by the complainants and offering support for all CWA programs.the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Alabama Power's results of operations. The final rule has been stayed since October 2015 byultimate 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.
On July 6, 2018, the U.S. Court of Appeals for the Sixth Circuit.
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 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.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Georgia Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Georgia Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Georgia Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Georgia Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Georgia Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Georgia Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these mattersmatter cannot be determined at this time.
Retail Regulatory Matters
GeorgiaAlabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the GeorgiaAlabama PSC. GeorgiaAlabama Power currently recovers its costs from the regulated retail business primarily through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs,Rate RSE, Rate CNP, Rate ECR, and Municipal Franchise Fee tariffs.Rate NDR. In addition, financing costs relatedthe Alabama PSC issues accounting orders to the construction of Plant Vogtle Units 3address current events impacting Alabama Power. See Notes 1 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 GeorgiaAlabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters, – Nuclear Construction"" respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the NCCR tariff. Also seerecovery balance of each regulatory clause for Alabama Power.
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Alabama Power in Item 7 of the Form 10-K for additional information.
GEORGIARate 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 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. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
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 September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Alabama Power under "Federal Tax Reform Legislation" and "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-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.
Request for Proposals for Future Generation
On September 21, 2018, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than 2023. Any purchases will depend upon the cost competitiveness of the respective offers as well as other options available to Alabama Power. The ultimate outcome of this matter cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – "Retail FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY –
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



"Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Fuel Cost Recovery"Alabama Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of Georgiabusiness. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Alabama Power in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.
RenewablesIn 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Alabama Power will adopt the new standard effective January 1, 2019.
Alabama Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



adoption date of January 1, 2019, without restating prior periods. Alabama Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Alabama Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Alabama Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Alabama Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Alabama Power has substantially completed its lease inventory and determined its most significant leases involve PPAs. While Alabama Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Alabama Power's balance sheet each totaling approximately $200 million, with no material impact on Alabama Power's statement of income.
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 September 30, 2018. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.39 billion for the first nine months of 2018, a decrease of $22 million as compared to the first nine months of 2017. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments partially offset by income tax refunds received in 2018. Net cash used for investing activities totaled $1.60 billion for the first nine months of 2018 primarily due to gross property additions related to environmental, distribution, transmission, and steam assets. Net cash provided from financing activities totaled $369 million for the first nine months of 2018 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2018 include increases of $2.40 billion in property, plant, and equipment primarily due to increases in AROs related to the CCR Rule and additions to distribution, transmission, and steam assets, $1.39 billion in AROs related to the CCR Rule and nuclear decommissioning, $504 million in additional paid-in capital primarily due to capital contributions from Southern Company, and $496 million in long-term debt primarily due to a senior note issuance. In addition, $321 million of long-term debt was reclassified as securities due within one year. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information related to changes in Alabama Power's AROs.
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. Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. An additional $201 million will be required through September 30, 2019 to fund maturities of long-term debt.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan""Environmental Matters" of GeorgiaAlabama Power in Item 7 of the Form 10-K for additional information regarding renewable energy projects.on Alabama Power's environmental compliance strategy.
On May 16, 2017, the Georgia PSCIn October 2018, Alabama Power's Board of Directors approved Georgia Power's requestupdates to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force baseits construction program that is currently estimated to total $1.8 billion for 2019, $1.6 billion for 2020, $1.6 billion for 2021, $1.4 billion for 2022, and $1.5 billion for 2023. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $0.3 billion for 2019, $0.1 billion for 2020, $0.2 billion for 2021, $0.2 billion for 2022, and $0.1 billion for 2023. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil-fuel-fired electric generating units.
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 be placed in service bychange, could change materially as Alabama Power continues to refine its assumptions underlying the endcost estimates and evaluate the method and timing of 2019.
During the nine months ended September 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that iscompliance activities. These costs are expected to begin in 2019 and are currently estimated to be placedapproximately $232 million for 2019, $238 million for 2020, $246 million for 2021, $252 million for 2022, and $258 million for 2023. See FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein, and Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in serviceItem 8 of the Form 10-K 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 fourth quarter 2017.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.
The ultimate outcomeSources of these matters cannot be determined at this time.Capital
Integrated Resource Plan
Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIALFINANCIAL CONDITION AND LIQUIDITY – "Retail Regulatory Matters – Integrated Resource Plan""Sources of GeorgiaCapital" of Alabama Power in Item 7 of the Form 10-K for additional information regardinginformation.
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 September 30, 2018, Alabama Power had approximately $702 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:
Expires     Expires Within One Year
2019 2020 2022 Total Unused Term Out No Term Out
(in millions)
$33
 $500
 $800
 $1,333
 $1,333
 $—
 $33
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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 September 30, 2018, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $854 million as of September 30, 2018. At September 30, 2018, Alabama Power had $120 million aggregate principal amount of fixed rate The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008 outstanding that were required to be reoffered within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held all of these bonds.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
 
Short-term Debt at
September 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$—
 —% $11
 2.2% $135
Short-term bank loan3
 3.7% 3
 3.7% 3
Total$3
 3.7% $14
 2.6%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At September 30, 2018, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 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$284
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power's triennial Integrated Resource Plan.Power (affiliate company of Alabama Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On March 7, 2017,September 28, 2018, Fitch assigned a negative rating outlook to the Georgiaratings of Southern Company and certain of its subsidiaries (including Alabama Power).
Also on September 28, 2018, Moody's revised its rating outlook for Alabama 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 Alabama Power, may be negatively impacted. The modifications to Rate RSE and other commitments approved by the Alabama PSC approved Georgia Power's decisionare expected to suspend work at a future generation site in Stewart County, Georgia, duehelp mitigate these potential adverse impacts to changing economics, including load forecastscertain credit metrics and lower fuel costs. The timingwill help Alabama Power meet its goal of recovery for costs incurredachieving an equity ratio of approximately $50 million will be determined55% by the Georgia PSCend of 2025. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power – Rate RSE" herein for additional information.
Financing Activities
In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. 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, Alabama Power plans to continue, when economically feasible, a future base rate case. The ultimate outcomeprogram to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Table of this matter cannot be determined at this time.Contents

Storm Damage Recovery
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operatingoperations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was $311 million. During September 2017,October 2018, Hurricane IrmaMichael caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferredcurrently estimates the costs of repairing the damage will total approximately $145 $125 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in the regulatory asset related$150 million, which will be charged to Georgia Power's storm damage was $360 million.reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of GeorgiaGeorgia Power's next base rate case, requiredwhich is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.
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.
Storm Damage Cost Recovery
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
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 provided 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 September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
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 became effective with 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 certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through a separate Mississippi Power cost rider. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation 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 is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $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 45% at September 30, 2018) to 50% by December 31, 2018. 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 are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.
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 September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 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 $20 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 $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to stormsthe 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 two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-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 a materialany adverse impact on Georgia Power's financial statements.customer rates.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Note 1Notes 3 and 12 to the financial statements of GeorgiaSouthern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Southern Power under "Storm Damage Recovery"– Construction Projects in Progress," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Georgia Power's storm damage reserve.Southern Company's capital requirements for its subsidiaries' construction programs.
Nuclear Construction
See Note 3 to the financial statements of Georgia PowerSouthern Company under "Retail Regulatory Matters – Nuclear"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, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcytariff.
In 2008,2009, the Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and testPSC certified construction of Plant Vogtle Units 3 and 4. UnderIn 2012, the termsNRC issued the related combined construction and operating licenses, which allowed full construction of the Vogtle 3two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and 4 Agreement, the Vogtle Owners agreedrelated facilities to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share ofbegin. Until March 2017, construction on Plant Vogtle Units 3 and 4 is 45.7%.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractorcontinued under the Vogtle 3 and 4 Agreement, which was 40% of the contracta substantially fixed price (approximately $1.7 billion based on Georgia Power's ownership interest).
Onagreement. In March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4,
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 whichwith the bankruptcy court approved on March 30, 2017.
EPC Contractor to allow construction to continue. The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired onin July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017 of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements.
Additionally, on June 9, 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, which was amendedWestinghouse provides facility design and restatedengineering services, procurement and technical support, and staff augmentation on July 20, 2017, for the EPC Contractor to transition construction management of Planta time and materials cost basis. The Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 isare 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.
EffectiveIn October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered intoexecuted the Bechtel Agreement, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will beis 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 connection withDecember 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue with construction of Plant Vogtle Units 3 and 4, (described below),with Southern Nuclear serving as project manager and Bechtel serving as the Vogtle Owners agreed onprimary construction contractor.
Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a term sheet to amendfull cost reforecast for the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, the holders of at least 90%project. Georgia Power's approximate proportionate share of the ownership interests inremaining estimated capital cost to complete Plant Vogtle Units 3 and 4 must voteby 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 September 30, 2018(b)
(4.3)
Remaining estimate to complete(a)
$4.1
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.
The table above reflects the $0.7 billion increase to continue construction if certain adverse events occur,the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted 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 (i)field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii)project and the Georgia PSC determinesPSC's order in the seventeenth VCM proceeding specifically states that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 willis not be recoveredsubject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in retail rates because suchthe current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 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 deemed unreasonable or imprudent; or (iv) anappropriately 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction budget containedcontingency estimate.
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 only recently began initial operation in the seventeenth VCM report by more than $1 billionglobal nuclear industry at this scale); or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.other
GEORGIA POWERSOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The term sheet also confirms thatissues could arise and change the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent forprojected schedule and estimated cost. Monthly construction production targets required to maintain the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017current project schedule continue to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDCsignificantly through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposesremainder of the AFUDC calculation, the ROE on costs between $4.418 billion2018 and $5.440 billion will alsointo 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be 10.00%retained and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
The ultimate outcome of these matters cannot be determined at this time.
Revised Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
 (in billions)
Estimated cost to complete$4.2
CWIP as of September 30, 20174.6
Guarantee Obligations(1.7)
Estimated capital costs$7.1
Vogtle Cost Settlement Agreement Revised Forecast(5.7)
Estimated net additional capital costs$1.4
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
 Cancellation Cost Estimate
 (in billions)
CWIP as of September 30, 2017$4.6
Financing costs collected, net of tax1.5
Cancellation costs(*)
0.4
Guarantee Obligations(1.7)
Estimated net cancellation cost$4.8
(*)The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of September 30, 2017, 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. On September 28, 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. 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. 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 (E) 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 IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.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 while construction proceeds.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 (ITAAC) and the related approvals by the NRC, may arise, while construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
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 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 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 continues,(as amended, and together with the risk remainsNovember 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that challengesthe Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with managementtheir performance as agent for the Vogtle Owners is limited to removal of contractors, subcontractors,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 vendors, labor productivity, fabrication, delivery, assembly,Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and installation4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of plant systems, structures,Plant Vogtle Units 3 and components,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, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC 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, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
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 Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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 expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and 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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 to 2022.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 combined with subsequent adverse action by the Georgia PSC could arisehave a material impact on Southern Company's results of operations, financial condition, and may further impact project scheduleliquidity.
The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and cost.approximately $188 million in related Customer Refunds). On August 31, 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.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia PowerSouthern Company in Item 1A ofherein and 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
As of September 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 September 2018, the DOE extended the conditional commitment to March 31, 2019. 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. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Southern Power
In April 2018, Southern Power completed the final stage of 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 $54 million, which were recorded in the first half of 2018.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On October 2, 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings.
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 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. On August 10, 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On May 4, 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.
On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Investments in Leveraged Leases
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Investments in Leveraged Leases" of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) 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 September 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 September 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
In December 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds) 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 approximately $188 million in related Customer Refunds). 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 did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast in the nineteenth VCM report filed with the Georgia PSC 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 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 only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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. 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

estimates. 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 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) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
The Southern Company system is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. The Southern Company system has substantially completed its lease inventory and determined its most significant leases involve PPAs, real estate, and communication towers where certain of Southern Company's subsidiaries are the lessee and PPAs where certain of Southern Company's subsidiaries are the lessor. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company's balance sheet each totaling approximately $2.1 billion, with no material impact on Southern Company's statement of income.
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 September 30, 2018. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $5.6 billion for the first nine months of 2018, an increase of $0.3 billion from the corresponding period in 2017. The increase in net cash provided from operating activities was primarily due to increased fuel cost recovery and the timing of vendor payments. Net cash used for investing activities totaled $3.5 billion for the first nine months of 2018 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the Southern Company Gas Dispositions. Net cash used for financing activities totaled $2.3 billion for the first nine months of 2018 primarily due to net redemptions and repurchases of long-term debt, common stock dividend payments, and a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities, and the issuance of common stock. 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 nine months of 2018 include the reclassification of $5.1 billion and $3.2 billion in total assets and liabilities held for sale, respectively, primarily associated with Gulf Power, as well as decreases of $2.8 billion and $0.4 billion in total assets and liabilities, respectively, associated with the Southern Company Gas Dispositions. See Note (J) to the Condensed Financial Statements under "Assets Held for Sale" and "Southern Company Gas" herein for additional information. After adjusting for these changes, other significant balance sheet changes include an increase of $4.0 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 second quarter 2018 charge related to the construction of Plant Vogtle Units 3 and 4; a decrease of $2.6 billion in long-term debt (including amounts due within one year) resulting from the repayment of long-term debt; an increase of $1.8 billion in noncontrolling interests primarily related to Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities; and an increase of $1.5 billion in ARO liabilities primarily related to revised estimates for ash pond closure costs at Alabama Power to comply with the CCR Rule. See Notes (A), (B), (F), and (J) to the Condensed Financial Statements under "Asset Retirement Obligations," "Nuclear Construction," "Financing Activities," and "Southern Power – Sale of Solar Facility Interests," respectively, herein for additional information.
At the end of the third quarter 2018, the market price of Southern Company's common stock was $43.60 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $24.18 per share, representing a market-to-book ratio of 180%, compared to $48.09, $23.99, and 201%, respectively, at the end of 2017. Southern Company's common stock dividend for the third quarter 2018 was $0.60 per share compared to $0.58 per share in the third quarter 2017.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements and contractual obligations. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019, Alabama Power purchased and held $120 million of pollution control revenue bonds, and Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $2.6 billion will be required through September 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The Southern Company system's construction program is currently estimated to total approximately $8.8 billion for 2018, $8.2 billion for 2019, $7.2 billion for 2020, $7.0 billion for 2021, and $6.7 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $0.5 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, as revised subsequent to Tax Reform Legislation. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and costs, which are immaterial to Southern Company, relating to assets divested during 2018 and held for sale at September 30, 2018. Estimated capital expenditures to comply with environmental laws and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 pending 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 fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Southern Company also plans to utilize the proceeds from the disposition of Gulf Power when completed for future capital needs. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on March 31, 2019, 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. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
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 September 30, 2018, Southern Company's current liabilities exceeded current assets by $3.6 billion due to long-term debt that is due within one year of $3.0 billion (including approximately $1.3 billion at the parent company, $0.3 billion at Alabama Power, $0.5 billion at Georgia Power, $0.2 billion at Mississippi Power, and $0.5 billion at Southern Company Gas) and notes payable of $2.6 billion (including approximately $2.0 billion at the parent company, $0.1 billion at Georgia Power, $0.1 billion at Gulf Power, $0.2 billion at Southern Power, and $0.1 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2018, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:
 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 Power—
33
500
800
 1,333
 1,333
 —
 —
 33
Georgia Power—
—
—
1,750
 1,750
 1,736
 —
 —
 —
Gulf Power20
25
235
—
 280
 280
 45
 45
 —
Mississippi Power—
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$20
$188
$735
$7,200
 $8,143
 $8,101
 $45
 $45
 $63
(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 2019, of which $22 million remains unused at September 30, 2018.
(c)
Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, and Southern Power Company contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. All but $40 million of the bank credit arrangements do not contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2018 was approximately $1.5 billion. In addition, at September 30, 2018, the traditional electric operating companies had approximately $573 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held approximately $120 million of its outstanding pollution control revenue bonds required to be remarketed.
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), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
  
Short-term Debt at
September 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 $611
 2.5% $1,323
 2.4% $3,008
Short-term bank debt 1,953
 2.9% 1,790
 3.0% 2,003
Total $2,564
 2.8% $3,113
 2.7%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Credit Rating Risk
At September 30, 2018, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2018 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$38
At BBB- and/or Baa3$578
At BB+ and/or Ba1(*)
$2,120
(*)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 August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.
On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Also 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 August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A.
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.
On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3.
On September 28, 2018, Moody's revised its rating outlooks for Southern Company, Alabama Power, and Georgia Power from negative to stable.
Also on September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and its subsidiaries (excluding Gulf Power and Mississippi Power).
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 3 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including 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 nine months of 2018, Southern Company issued approximately 9.2 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $338 million.
In addition, during the third quarter 2018, Southern Company issued a total of approximately 12.1 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $540 million, net of approximately $5 million in commissions. Subsequent to September 30, 2018, Southern Company issued an additional approximately 2.5 million shares of common stock through at-the-market issuances and received cash proceeds of approximately $107 million, net of approximately $1 million in commissions.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2018:
Company
Senior
Note
Issuances
 Senior Note Maturities, Redemptions, and Repurchases 
Revenue Bond
Maturities, Redemptions, and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other Long-Term Debt Redemptions
and Maturities(a)
 (in millions)
Southern Company(b)
$750
 $1,000
 $—
 $—
 $—
Alabama Power500
 —
 —
 —
 —
Georgia Power—
 1,000
 469
 —
 107
Mississippi Power600
 —
 43
 —
 900
Southern Power—
 350
 —
 —
 420
Southern Company Gas—
 —
 200
 100
 —
Other—
 —
 —
 —
 10
Elimination(c)
—
 —
 —
 —
 (1)
Southern Company Consolidated$1,850
 $2,350
 $712
 $100
 $1,436
(a)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(b)Represents the Southern Company parent entity.
(c)Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's Consolidated Financial Statements.
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 March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.
In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on no less than 30 days' demand by the bank.
In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.
In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to a short-term uncommitted bank credit arrangement.
In the third quarter 2018, Southern Company repaid at maturity $500 million aggregate principal amount of 1.55% Senior Notes and $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes.
Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. These bonds may be remarketed to the public in the future.
In January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.
In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.
In March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. The proceeds of this loan, together with the proceeds of Mississippi Power's $600 million senior notes issuances, were used to repay Mississippi Power's $900 million unsecured floating rate term loan.
Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.
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.
During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to certain of its renewable facilities. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.
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 repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.
In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in November 2018.
Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.
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.

Table of Contents

PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2018, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (D) and Note (I) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
(b)Changes in internal controls over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 2018 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.

Table of Contents

ALABAMA POWER COMPANY

Table of Contents

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Operating Revenues:       
Retail revenues$1,584
 $1,595
 $4,208
 $4,155
Wholesale revenues, non-affiliates74
 77
 213
 210
Wholesale revenues, affiliates14
 18
 96
 83
Other revenues68
 50
 199
 158
Total operating revenues1,740
 1,740
 4,716
 4,606
Operating Expenses:       
Fuel356
 343
 1,028
 944
Purchased power, non-affiliates64
 57
 176
 132
Purchased power, affiliates69
 55
 149
 117
Other operations and maintenance401
 406
 1,191
 1,177
Depreciation and amortization192
 185
 570
 549
Taxes other than income taxes97
 93
 289
 284
Total operating expenses1,179
 1,139
 3,403
 3,203
Operating Income561
 601
 1,313
 1,403
Other Income and (Expense):       
Allowance for equity funds used during construction16
 11
 43
 27
Interest expense, net of amounts capitalized(82) (76) (240) (229)
Other income (expense), net9
 10
 24
 35
Total other income and (expense)(57) (55) (173) (167)
Earnings Before Income Taxes504
 546
 1,140
 1,236
Income taxes127
 216
 272
 493
Net Income377
 330
 868
 743
Dividends on Preferred and Preference Stock4
 5
 11
 14
Net Income After Dividends on Preferred and Preference Stock$373
 $325
 $857
 $729

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income$377
 $330
 $868
 $743
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $1, and $2, respectively		1
 1
 3
 3
Total other comprehensive income (loss)1
 1
 3
 3
Comprehensive Income$378
 $331
 $871
 $746
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

Table of Contents

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$868
 $743
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total683
 666
Deferred income taxes104
 260
Allowance for equity funds used during construction(43) (27)
Settlement of asset retirement obligations(31) (20)
Other, net(6) 59
Changes in certain current assets and liabilities —   
-Receivables(207) (163)
-Prepayments(26) (28)
-Materials and supplies(69) (29)
-Other current assets66
 33
-Accounts payable(194) (125)
-Accrued taxes225
 159
-Accrued compensation(41) (48)
-Retail fuel cost over recovery—
 (76)
-Other current liabilities60
 7
Net cash provided from operating activities1,389
 1,411
Investing Activities:   
Property additions(1,529) (1,211)
Nuclear decommissioning trust fund purchases(207) (174)
Nuclear decommissioning trust fund sales207
 174
Cost of removal, net of salvage(78) (82)
Change in construction payables30
 105
Other investing activities(23) (29)
Net cash used for investing activities(1,600) (1,217)
Financing Activities:   
Proceeds —   
Senior notes500
 550
Capital contributions from parent company495
 337
Preferred stock—
 250
Redemptions —   
Senior notes—
 (200)
Pollution control revenue bonds—
 (36)
Payment of common stock dividends(602) (536)
Other financing activities(24) (26)
Net cash provided from financing activities369
 339
Net Change in Cash, Cash Equivalents, and Restricted Cash158
 533
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period544
 420
Cash, Cash Equivalents, and Restricted Cash at End of Period$702
 $953
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $15 and $10 capitalized for 2018 and 2017, respectively)$220
 $217
Income taxes, net30
 146
Noncash transactions — Accrued property additions at end of period275
 189
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

Table of Contents

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $702
 $544
Receivables —    
Customer accounts receivable 455
 355
Unbilled revenues 159
 162
Under recovered regulatory clause revenues 48
 —
Affiliated 68
 43
Other accounts and notes receivable 54
 55
Accumulated provision for uncollectible accounts (9) (9)
Fossil fuel stock 117
 184
Materials and supplies 536
 458
Prepaid expenses 59
 85
Other regulatory assets, current 141
 124
Other current assets 8
 5
Total current assets 2,338
 2,006
Property, Plant, and Equipment:    
In service 29,568
 27,326
Less: Accumulated provision for depreciation 9,932
 9,563
Plant in service, net of depreciation 19,636
 17,763
Nuclear fuel, at amortized cost 316
 339
Construction work in progress 1,457
 908
Total property, plant, and equipment 21,409
 19,010
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 63
 67
Nuclear decommissioning trusts, at fair value 938
 903
Miscellaneous property and investments 127
 124
Total other property and investments 1,128
 1,094
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 236
 239
Deferred under recovered regulatory clause revenues 88
 54
Other regulatory assets, deferred 1,209
 1,272
Other deferred charges and assets 202
 189
Total deferred charges and other assets 1,735
 1,754
Total Assets $26,610
 $23,864
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


Table of Contents

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At September 30, 2018 At December 31, 2017
  (in millions)
Current Liabilities:    
Securities due within one year $321
 $—
Accounts payable —    
Affiliated 341
 327
Other 425
 585
Customer deposits 96
 92
Accrued taxes —    
Accrued income taxes 97
 9
Other accrued taxes 132
 45
Accrued interest 81
 77
Accrued compensation 169
 205
Asset retirement obligations, current 111
 7
Other regulatory liabilities, current 57
 1
Other current liabilities 46
 52
Total current liabilities 1,876
 1,400
Long-term Debt 7,803
 7,628
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 2,882
 2,760
Deferred credits related to income taxes 2,051
 2,082
Accumulated deferred ITCs 107
 112
Employee benefit obligations 283
 304
Asset retirement obligations 3,090
 1,702
Other cost of removal obligations 542
 609
Other regulatory liabilities, deferred 52
 84
Other deferred credits and liabilities 48
 63
Total deferred credits and other liabilities 9,055
 7,716
Total Liabilities 18,734
 16,744
Redeemable Preferred Stock 291
 291
Common Stockholder's Equity:    
Common stock, par value $40 per share —    
Authorized — 40,000,000 shares    
Outstanding — 30,537,500 shares 1,222
 1,222
Paid-in capital 3,490
 2,986
Retained earnings 2,902
 2,647
Accumulated other comprehensive loss (29) (26)
Total common stockholder's equity 7,585
 6,829
Total Liabilities and Stockholder's Equity $26,610
 $23,864
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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


OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information on Alabama Power's established retail tariff.
Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)
(% change)
(change in millions)
(% change)
$48 14.8 $128 17.6
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2018 was $373 million compared to $325 million for the corresponding period in 2017. Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2018 was $857 million compared to $729 million for the corresponding period in 2017. These increases were primarily related to an increase in retail revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2017 and a decrease in income tax expense, partially offset by customer bill credits related to the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Retail Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(11) (0.7) $53 1.3
In the third quarter 2018, retail revenues were $1.58 billion compared to $1.60 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $4.21 billion compared to $4.16 billion for the corresponding period in 2017.
Details of the changes in retail revenues were as follows:
 Third Quarter 2018
Year-to-Date 2018
 (in millions)
(% change)
(in millions)
(% change)
Retail – prior year$1,595
   $4,155
  
Estimated change resulting from –       
Rates and pricing(87) (5.5) (195) (4.7)
Sales decline(2) (0.1) (8) (0.1)
Weather37
 2.3
 130
 3.1
Fuel and other cost recovery41
 2.6
 126
 3.0
Retail – current year$1,584
 (0.7)% $4,208
 1.3%
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to customer bill credits related to the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted commercial KWH sales decreased 1.1% and 1.4% for the third quarter and year-to-date 2018, respectively, and weather-adjusted residential KWH sales decreased 0.3% and 0.5% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to lower customer usage related to energy efficiency. Industrial KWH sales increased 1.3% and 2.4% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, and in the pipelines sector, partially offset by a decrease in demand in the paper and chemicals sectors, primarily due to customer maintenance outages and on-site cogeneration.
Revenues resulting from changes in weather increased in the third quarter and year-to-date 2018 due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2017. For the third quarter 2018, the resulting increases were 3.9% and 2.2% for residential and commercial sales revenues, respectively. For year-to-date 2018, the resulting increases were 5.7% and 2.3% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to increases in KWH generation and the average cost of fuel.
Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Wholesale Revenues – Affiliates
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(4) (22.2) $13 15.7
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
For year-to-date 2018, wholesale revenues from sales to affiliates were $96 million compared to $83 million for the corresponding period in 2017. The increase was primarily due to a 12% increase in the price of energy and a 3% increase in KWH sales as a result of increased demand due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$18 36.0 $41 25.9
In the third quarter 2018, other revenues were $68 million compared to $50 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $199 million compared to $158 million for the corresponding period in 2017. These increases were primarily due to revenues related to unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606. The year-to-date 2018 increase was partially offset by decreases in open access transmission tariff revenues primarily due to expected declines in customers' needs and a lower rate related to the Tax Reform Legislation.
Fuel and Purchased Power Expenses
 Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
 (change in millions)
(% change) (change in millions) (% change)
Fuel$13
 3.8 $84
 8.9
Purchased power – non-affiliates7
 12.3 44
 33.3
Purchased power – affiliates14
 25.5 32
 27.4
Total fuel and purchased power expenses$34
   $160
  
In the third quarter 2018, fuel and purchased power expenses were $489 million compared to $455 million for the corresponding period in 2017. The increase was primarily due to a $23 million increase related to the volume of KWHs generated and purchased and a $16 million increase related to the average cost of fuel, partially offset by a $5 million decrease in the average cost of purchased power.
For year-to-date 2018, fuel and purchased power expenses were $1.35 billion compared to $1.19 billion for the corresponding period in 2017. The increase was primarily due to a $98 million increase related to the volume of KWHs generated and purchased and a $32 million increase related to the average cost of fuel.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In addition, fuel expense increased $30 million year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.
Details of Alabama Power's generation and purchased power were as follows:
 Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018
Year-to-Date 2017
Total generation (in billions of KWHs)
16 16 47 46
Total purchased power (in billions of KWHs)
3 2 6 5
Sources of generation (percent) —
       
Coal54 52 52 49
Nuclear24 24 22 25
Gas18 19 19 20
Hydro4 5 7 6
Cost of fuel, generated (in cents per net KWH)(a) —
       
Coal2.74 2.61 2.74 2.61
Nuclear0.78 0.75 0.77 0.75
Gas2.80 2.72 2.72 2.74
Average cost of fuel, generated (in cents per net KWH)(a)(b)
2.27 2.17 2.27 2.15
Average cost of purchased power (in cents per net KWH)(c)
5.43 5.65 5.59 5.57
(a)Cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment for year-to-date 2018 associated with the Alabama PSC accounting order related to excess deferred income taxes.
(b)KWHs generated by hydro are excluded from the average cost of fuel, generated.
(c)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2018, fuel expense was $356 million compared to $343 million for the corresponding period in 2017. The increase was primarily due to a 16.6% decrease in the volume of KWHs generated by hydro facilities due to lower rainfall, a 5.0% increase in the average cost of coal per KWH generated, a 4.0% increase in the average cost of nuclear fuel per KWH generated, and a 3.9% decrease in the volume of KWHs generated by nuclear facilities due to the timing of outages. In addition, the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, increased 2.9% and the volume of KWHs generated by coal increased 2.0%. These increases were partially offset by an 8.4% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2018, fuel expense was $1.03 billion compared to $944 million for the corresponding period in 2017. The increase was primarily due to a 10.8% decrease in the volume of KWHs generated by nuclear facilities due to outages, a 6.9% increase in the volume of KWHs generated by coal, and a 5.0% increase in the average cost of coal per KWH generated. These increases were partially offset by an 11.7% increase in the volume of KWHs generated by hydro facilities due to the timing of rainfall and a 4.1% decrease in the volume of KWHs generated by natural gas.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In addition, fuel expense increased $30 million year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.
Purchased Power – Non-Affiliates
In the third quarter 2018, purchased power expense from non-affiliates was $64 million compared to $57 million for the corresponding period in 2017. The increase was primarily related to a 14.8% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, purchased power expense from non-affiliates was $176 million compared to $132 million for the corresponding period in 2017. The increase was primarily related to a 24.3% increase in the amount of energy purchased and a 6.7% increase in the average cost of purchased power per KWH due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2018, purchased power expense from affiliates was $69 million compared to $55 million for the corresponding period in 2017. The increase was primarily related to a 28% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, purchased power expense from affiliates was $149 million compared to $117 million for the corresponding period in 2017. The increase was primarily related to a 35% increase in the amount of energy purchased as a result of colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(5) (1.2) $14 1.2
For year-to-date 2018, other operations and maintenance expenses were $1.19 billion compared to $1.18 billion for the corresponding period in 2017. The increase was primarily due to $33 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 $29 million primarily due to additional line maintenance. These increases were partially offset by a $23 million decrease in steam generation costs primarily due to the timing of outages, an $8 million decrease in employee benefits as a result of amounts capitalized in connection with an increase in construction projects, a $7 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects, and a $6 million decrease in property insurance primarily due to the receipt of refunds.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 3.8 $21 3.8
In the third quarter 2018, depreciation and amortization was $192 million compared to $185 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $570 million compared to $549 million for the corresponding period in 2017. These increases were primarily due to additional plant in service related to steam generation, transmission, and distribution assets. See Note 1 to the financial statements of Alabama Power under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$5 45.5 $16 59.3
In the third quarter 2018, AFUDC equity was $16 million compared to $11 million for the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $43 million compared to $27 million for the corresponding period in 2017. These increases were primarily due to an increase in capital expenditures related to environmental and transmission projects.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 7.9 $11 4.8
In the third quarter 2018, interest expense, net of amounts capitalized was $82 million compared to $76 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $240 million compared to $229 million for the corresponding period in 2017. These increases were primarily due to an increase in the average debt outstanding and higher interest rates, partially offset by an increase in the amounts capitalized.
Other Income (Expense), Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(1) (10.0) $(11) (31.4)
For year-to-date 2018, other income (expense), net was $24 million compared to $35 million for the corresponding period in 2017. This decrease was 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Income Taxes
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(89) (41.2) $(221) (44.8)
In the third quarter 2018, income taxes were $127 million compared to $216 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $272 million compared to $493 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 earnings. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" and Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be impacted by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Alabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and 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 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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" and "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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 October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Alabama Power is evaluating the extent of potential impacts on legacy units. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
On April 20, 2018, the Alabama Environmental Management Commission approved a state CCR rule that has been provided to the EPA for a six-month review period. This state CCR rule is generally consistent with the federal CCR Rule. The ultimate outcome of this matter cannot be determined at this time.
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As further analysis is performed and closure details are developed with respect to ash pond closures, Alabama Power expects to periodically update these cost estimates. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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.
Nuclear Decommissioning
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.
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.
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.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Alabama Power has ownership interests in 20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Alabama Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
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 concluded.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Alabama Power's results of operations. 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.
On July 6, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating the FERC's 2013 order issuing a new 30-year license to Alabama Power for seven hydroelectric developments on the Coosa River and remanding the proceeding to the FERC for further proceedings. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Alabama Power in Item 7 of the Form 10-K for additional information.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 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. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.
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 September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Alabama Power under "Federal Tax Reform Legislation" and "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-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.
Request for Proposals for Future Generation
On September 21, 2018, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than 2023. Any purchases will depend upon the cost competitiveness of the respective offers as well as other options available to Alabama Power. 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 –
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



"Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Alabama Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Alabama Power will adopt the new standard effective January 1, 2019.
Alabama Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



adoption date of January 1, 2019, without restating prior periods. Alabama Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Alabama Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Alabama Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Alabama Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Alabama Power has substantially completed its lease inventory and determined its most significant leases involve PPAs. While Alabama Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Alabama Power's balance sheet each totaling approximately $200 million, with no material impact on Alabama Power's statement of income.
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 September 30, 2018. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.39 billion for the first nine months of 2018, a decrease of $22 million as compared to the first nine months of 2017. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments partially offset by income tax refunds received in 2018. Net cash used for investing activities totaled $1.60 billion for the first nine months of 2018 primarily due to gross property additions related to environmental, distribution, transmission, and steam assets. Net cash provided from financing activities totaled $369 million for the first nine months of 2018 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2018 include increases of $2.40 billion in property, plant, and equipment primarily due to increases in AROs related to the CCR Rule and additions to distribution, transmission, and steam assets, $1.39 billion in AROs related to the CCR Rule and nuclear decommissioning, $504 million in additional paid-in capital primarily due to capital contributions from Southern Company, and $496 million in long-term debt primarily due to a senior note issuance. In addition, $321 million of long-term debt was reclassified as securities due within one year. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information related to changes in Alabama Power's AROs.
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. Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. An additional $201 million will be required through September 30, 2019 to fund maturities of long-term debt.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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.
In October 2018, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $1.8 billion for 2019, $1.6 billion for 2020, $1.6 billion for 2021, $1.4 billion for 2022, and $1.5 billion for 2023. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $0.3 billion for 2019, $0.1 billion for 2020, $0.2 billion for 2021, $0.2 billion for 2022, and $0.1 billion for 2023. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO2 emissions from fossil-fuel-fired electric generating units.
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, could change materially as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities. These costs 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, $252 million for 2022, and $258 million for 2023. See FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein, and 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 for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At September 30, 2018, Alabama Power had approximately $702 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:
Expires     Expires Within One Year
2019 2020 2022 Total Unused Term Out No Term Out
(in millions)
$33
 $500
 $800
 $1,333
 $1,333
 $—
 $33
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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 September 30, 2018, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $854 million as of September 30, 2018. At September 30, 2018, Alabama Power had $120 million aggregate principal amount of fixed rate The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008 outstanding that were required to be reoffered within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held all of these bonds.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
 
Short-term Debt at
September 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$—
 —% $11
 2.2% $135
Short-term bank loan3
 3.7% 3
 3.7% 3
Total$3
 3.7% $14
 2.6%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At September 30, 2018, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 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$284
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate company of Alabama Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.
On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Alabama Power).
Also on September 28, 2018, Moody's revised its rating outlook for Alabama 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 Alabama Power, may be negatively impacted. The modifications to Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power – Rate RSE" herein for additional information.
Financing Activities
In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. 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, 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.

Table of Contents

GEORGIA POWER COMPANY

Table of Contents

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Operating Revenues:       
Retail revenues$2,425
 $2,402
 $6,112
 $5,995
Wholesale revenues, non-affiliates43
 45
 123
 124
Wholesale revenues, affiliates4
 6
 17
 23
Other revenues121
 93
 349
 284
Total operating revenues2,593
 2,546
 6,601
 6,426
Operating Expenses:       
Fuel480
 482
 1,269
 1,297
Purchased power, non-affiliates106
 119
 338
 310
Purchased power, affiliates206
 161
 555
 470
Other operations and maintenance460
 430
 1,325
 1,248
Depreciation and amortization232
 225
 690
 669
Taxes other than income taxes118
 112
 332
 311
Estimated loss on Plant Vogtle Units 3 and 4—
 —
 1,060
 —
Total operating expenses1,602
 1,529
 5,569
 4,305
Operating Income991
 1,017
 1,032
 2,121
Other Income and (Expense):       
Interest expense, net of amounts capitalized(95) (105) (303) (310)
Other income (expense), net30
 22
 104
 95
Total other income and (expense)(65) (83) (199) (215)
Earnings Before Income Taxes926
 934
 833
 1,906
Income taxes262
 350
 212
 705
Net Income664
 584
 621
 1,201
Dividends on Preferred and Preference Stock—
 4
 —
 13
Net Income After Dividends
on Preferred and Preference Stock		$664
 $580
 $621
 $1,188
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income$664
 $584
 $621
 $1,201
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $1, respectively		1
 1
 3
 2
Total other comprehensive income (loss)1
 1
 3
 2
Comprehensive Income$665
 $585
 $624
 $1,203
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

Table of Contents

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$621
 $1,201
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total854
 821
Deferred income taxes(185) 328
Allowance for equity funds used during construction(50) (29)
Pension, postretirement, and other employee benefits(46) (42)
Settlement of asset retirement obligations(82) (95)
Estimated loss on Plant Vogtle Units 3 and 41,060
 —
Other, net9
 (51)
Changes in certain current assets and liabilities —   
-Receivables(205) (254)
-Fossil fuel stock70
 (2)
-Prepaid income taxes231
 (5)
-Other current assets(36) (24)
-Accounts payable109
 (161)
-Accrued taxes26
 (52)
-Accrued compensation(32) (60)
-Retail fuel cost over recovery—
 (84)
-Other current liabilities(111) (11)
Net cash provided from operating activities2,233
 1,480
Investing Activities:   
Property additions(2,276) (1,907)
Nuclear decommissioning trust fund purchases(638) (411)
Nuclear decommissioning trust fund sales633
 406
Cost of removal, net of salvage(71) (54)
Change in construction payables, net of joint owner portion72
 180
Payments pursuant to LTSAs(52) (59)
Asset dispositions138
 63
Other investing activities(19) (52)
Net cash used for investing activities(2,213) (1,834)
Financing Activities:   
Increase (decrease) in notes payable, net102
 (391)
Proceeds —   
Capital contributions from parent company2,335
 412
Senior notes—
 1,350
Short-term borrowings—
 700
Other long-term debt—
 370
Redemptions and repurchases —   
Senior notes(1,000) (450)
Pollution control revenue bonds(469) (65)
Short-term borrowings(150) (300)
Other long-term debt(100) —
Payment of common stock dividends(1,043) (961)
Premiums on redemption and repurchases of senior notes(152) —
Other financing activities(15) (48)
Net cash provided from (used for) financing activities(492) 617
Net Change in Cash, Cash Equivalents, and Restricted Cash(472) 263
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period852
 3
Cash, Cash Equivalents, and Restricted Cash at End of Period$380
 $266
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $19 and $17 capitalized for 2018 and 2017, respectively)$315
 $284
Income taxes, net141
 369
Noncash transactions — Accrued property additions at end of period670
 470
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

Table of Contents

GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $380
 $852
Receivables —    
Customer accounts receivable 747
 544
Unbilled revenues 245
 255
Under recovered fuel clause revenues 105
 165
Joint owner accounts receivable 208
 262
Affiliated 39
 24
Other accounts and notes receivable 96
 76
Accumulated provision for uncollectible accounts (3) (3)
Fossil fuel stock 244
 314
Materials and supplies 494
 504
Prepaid expenses 77
 216
Other regulatory assets, current 199
 205
Other current assets 91
 14
Total current assets 2,922
 3,428
Property, Plant, and Equipment:    
In service 35,671
 34,861
Less: Accumulated provision for depreciation 12,029
 11,704
Plant in service, net of depreciation 23,642
 23,157
Nuclear fuel, at amortized cost 528
 544
Construction work in progress 4,655
 4,613
Total property, plant, and equipment 28,825
 28,314
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 50
 53
Nuclear decommissioning trusts, at fair value 933
 929
Miscellaneous property and investments 61
 59
Total other property and investments 1,044
 1,041
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 519
 516
Other regulatory assets, deferred 3,041
 2,932
Other deferred charges and assets 510
 548
Total deferred charges and other assets 4,070
 3,996
Total Assets $36,861
 $36,779
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.


Table of Contents

GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At September 30, 2018 At December 31, 2017
  (in millions)
Current Liabilities:    
Securities due within one year $511
 $857
Notes payable 102
 150
Accounts payable —    
Affiliated 515
 493
Other 909
 834
Customer deposits 275
 270
Accrued taxes 345
 344
Accrued interest 108
 123
Accrued compensation 185
 219
Asset retirement obligations, current 193
 270
Other regulatory liabilities, current 151
 191
Other current liabilities 180
 198
Total current liabilities 3,474
 3,949
Long-term Debt 9,863
 11,073
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 2,999
 3,175
Deferred credits related to income taxes 3,218
 3,248
Accumulated deferred ITCs 264
 248
Employee benefit obligations 650
 659
Asset retirement obligations, deferred 2,401
 2,368
Other deferred credits and liabilities 141
 128
Total deferred credits and other liabilities 9,673
 9,826
Total Liabilities 23,010
 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 9,670
 7,328
Retained earnings 3,792
 4,215
Accumulated other comprehensive loss (9) (10)
Total common stockholder's equity 13,851
 11,931
Total Liabilities and Stockholder's Equity $36,861
 $36,779
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


THIRD QUARTER 2018 vs. THIRD 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 scheduled to be filed by July 1, 2019. The Georgia PSC also approved an increase to Georgia Power's retail equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on the Tax Reform Settlement Agreement.
Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction. 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 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). 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 did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast (or any related financing costs) in the nineteenth VCM report filed with the Georgia PSC 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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 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. Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain provisions of the Vogtle Owner Term Sheet.
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 September 2018, the DOE extended the conditional commitment to March 31, 2019. 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.
The ultimate outcome of these matters cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on Plant Vogtle Units 3 and 4.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$84 14.5 $(567) (47.7)
Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2018 was $664 million compared to $580 million for the corresponding period in 2017. The increase was primarily due to lower federal income tax expense as a result of the Tax Reform Legislation and an increase in retail revenues associated with customer growth and warmer weather in the third quarter 2018 compared to the corresponding period in 2017. Partially offsetting the increase were revenues deferred as a regulatory liability for future customer bill credits related to the Tax Reform Legislation as well as higher non-fuel operations and maintenance expenses.
For year-to-date 2018, net income after dividends on preferred and preference stock was $621 million compared to $1.19 billion for the corresponding period in 2017. The decrease was primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4, revenues deferred as a regulatory liability for future customer bill credits related to the Tax Reform Legislation, and higher non-fuel operations and maintenance expenses. Partially offsetting the decrease were lower federal income tax expense as a result of the Tax Reform Legislation and an increase in retail revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on regulatory actions related to the Tax Reform Legislation. Also, 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Retail Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$23 1.0 $117 2.0
In the third quarter 2018, retail revenues were $2.43 billion compared to $2.40 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $6.11 billion compared to $6.00 billion for the corresponding period in 2017.
Details of the changes in retail revenues were as follows:
 Third Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Retail – prior year$2,402
   $5,995
  
Estimated change resulting from –       
Rates and pricing(87) (3.6) (196) (3.2)
Sales growth44
 1.9
 70
 1.2
Weather34
 1.4
 139
 2.3
Fuel cost recovery32
 1.3
 104
 1.7
Retail – current year$2,425
 1.0 % $6,112
 2.0 %
Revenues associated with changes in rates and pricing decreased in the third 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 bill credits related to the Tax Reform Legislation and decreases in revenues recognized under the NCCR tariff, also primarily related to the Tax Reform Legislation. Partially offsetting the decrease for year-to-date 2018 were higher contributions from variable demand-driven pricing from commercial and industrial customers. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on regulatory actions related to the Tax Reform Legislation. Also, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information related to the NCCR tariff.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales increased 3.3% and 1.9% and weather-adjusted commercial KWH sales increased 2.1% and 1.8% for the third quarter and year-to-date 2018, respectively, largely due to customer growth. Weather-adjusted industrial KWH sales increased 2.5% and 1.2% for the third quarter and year-to-date 2018, respectively. The increases were primarily driven by increased demand in the paper sector as a result of increased export demand and for shipping supplies resulting from increased electronic commerce, the lumber sector as a result of increased construction activity, and the rubber sector as a result of increased demand by the tire industry. Additionally, customer usage for all customer classes increased in the third quarter and year-to-date 2018 due to the negative impacts of Hurricane Irma during the corresponding periods in 2017.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to increased energy sales driven by higher purchased power costs and warmer weather in the third quarter 2018. Additionally, the increase for year-to-date 2018 was due to colder weather in the first quarter 2018 and warmer weather in the second quarter 2018. 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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 – Affiliates
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(2) (33.3) $(6) (26.1)
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.
For year-to-date 2018, wholesale revenues from sales to affiliates were $17 million compared to $23 million for the corresponding period in 2017. The decrease was due to a 54.3% decrease in KWH sales primarily due to the higher cost of Georgia Power-owned generation as compared to the market cost of available energy.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$28 30.1 $65 22.9
In the third quarter 2018, other revenues were $121 million compared to $93 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $349 million compared to $284 million for the corresponding period in 2017. The increases were primarily due to $24 million and $62 million of revenues in the third quarter and year-to-date 2018, respectively, primarily from unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.
Fuel and Purchased Power Expenses
 Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
 (change in millions) (% change) (change in millions) (% change)
Fuel$(2) (0.4) $(28) (2.2)
Purchased power – non-affiliates(13) (10.9) 28
 9.0
Purchased power – affiliates45
 28.0
 85
 18.1
Total fuel and purchased power expenses$30
   $85
  
In the third quarter 2018, total fuel and purchased power expenses were $792 million compared to $762 million in the corresponding period in 2017. The increase was primarily due to a $43 million net increase related to the volume of KWHs generated and purchased due to warmer weather, partially offset by a $13 million decrease related to the average cost of purchased power primarily due to lower natural gas prices.
For year-to-date 2018, total fuel and purchased power expenses were $2.16 billion compared to $2.08 billion in the corresponding period in 2017. The increase was primarily due to a $77 million increase related to the volume of KWHs purchased due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 and a $10 million net increase in the average cost of fuel and purchased power.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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:
 Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in billions of KWHs)
18 18 49 48
Total purchased power (in billions of KWHs)
8 7 22 20
Sources of generation (percent) —
       
Gas44 41 43 41
Coal32 35 30 33
Nuclear22 23 25 24
Hydro2 1 2 2
Cost of fuel, generated (in cents per net KWH) —
       
Gas2.58 2.63 2.64 2.71
Coal3.14 3.08 3.25 3.17
Nuclear0.83 0.84 0.83 0.84
Average cost of fuel, generated (in cents per net KWH)
2.36 2.38 2.36 2.40
Average cost of purchased power (in cents per net KWH)(*)
4.52 4.68 4.70 4.63
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
For year-to-date 2018, fuel expense was $1.27 billion compared to $1.30 billion in the corresponding period in 2017. The decrease was primarily due to an 8.0% decrease in the volume of KWHs generated by coal largely due to scheduled generation outages and a 2.6% decrease in the average cost of fuel per KWH generated by natural gas, partially offset by a 6.8% increase in the volume of KWHs generated by natural gas and a 2.5% increase in the average cost of fuel per KWH generated by coal.
Purchased Power – Non-Affiliates
In the third quarter 2018, purchased power expense from non-affiliates was $106 million compared to $119 million in the corresponding period in 2017. The decrease was primarily due to a 17.8% decrease in the volume of KWHs purchased primarily due to the higher market cost of available energy as compared to Southern Company system resources, partially offset by an 8.3% increase in the average cost per KWH purchased primarily due to higher energy prices.
For year-to-date 2018, purchased power expense from non-affiliates was $338 million compared to $310 million in the corresponding period in 2017. The increase was primarily due to a 10.2% increase in the average cost per KWH purchased primarily 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Purchased Power – Affiliates
In the third quarter 2018, purchased power expense from affiliates was $206 million compared to $161 million in the corresponding period in 2017. The increase was primarily due to a 28.3% increase in the volume of KWHs purchased due to scheduled generation outages and warmer weather, partially offset by a 3.4% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.
For year-to-date 2018, purchased power expense from affiliates was $555 million compared to $470 million in the corresponding period in 2017. The increase was primarily due to an 11.1% 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 and third quarters 2018.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$30 7.0 $77 6.2
In the third quarter 2018, other operations and maintenance expenses were $460 million compared to $430 million in the corresponding period in 2017. The increase was primarily due to $23 million of expenses from unregulated sales of products and services that were reclassified to 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 was $11 million in transmission and distribution costs, primarily due to additional line maintenance and billing adjustments with integrated transmission system owners, partially offset by a decrease of $9 million in certain employee compensation and benefit costs.
For year-to-date 2018, other operations and maintenance expenses were $1.33 billion compared to $1.25 billion in the corresponding period in 2017. The increase was primarily due to $58 million of expenses from unregulated sales of products and services that were reclassified to 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 increases of $11 million in demand-side management costs related to the timing of new programs, $8 million related to additional distribution line maintenance, and $8 million in billing adjustments with integrated transmission system owners, partially offset by decreases of $14 million in certain employee compensation and benefit costs and $10 million related to affiliate labor billing adjustments.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.
Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 3.1 $21 3.1
In the third quarter 2018, depreciation and amortization was $232 million compared to $225 million in the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $690 million compared to $669 million in the corresponding period in 2017. The increases were primarily due to increases of $8 million and $23 million related to additional plant in service in the third quarter and year-to-date 2018, respectively.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Taxes Other Than Income Taxes
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 5.4 $21 6.8
In the third quarter 2018, taxes other than income taxes were $118 million compared to $112 million in the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $332 million compared to $311 million in the corresponding period in 2017. The increases were primarily due to increases in property taxes of $4 million and $11 million in the third quarter and year-to-date 2018, respectively, as a result of an increase in the assessed value of property and increases in municipal franchise fees of $3 million and $10 million in the third quarter and year-to-date 2018, respectively, largely related to higher retail revenues.
Estimated Loss on Plant Vogtle Units 3 and 4
Third Quarter 2018 vs. Third Quarter 2017Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)(% change)(change in millions)(% change)
$—N/M$1,060N/M
N/M - Not meaningful
In the second quarter 2018, an estimated probable loss of $1.1 billion was recorded to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4, which reflects the increase in costs included in the revised base capital cost forecast for which Georgia Power did not seek rate recovery and costs included in the revised construction contingency estimate for which Georgia Power may seek rate recovery as and when such costs are appropriately included in the base capital cost forecast. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(10) (9.5) $(7) (2.3)
In the third quarter 2018, interest expense, net of amounts capitalized was $95 million compared to $105 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $303 million compared to $310 million in the corresponding period in 2017. The decreases were primarily due to a decrease in outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information.
Other Income (Expense), Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$8 36.4 $9 9.5
In the third quarter 2018, other income (expense), net was $30 million compared to $22 million in the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $104 million compared to $95 million in the corresponding period in 2017. The increases were primarily due to increases in AFUDC equity of $14 million and $21 million in the third quarter and year-to-date 2018, respectively, resulting from a higher AFUDC rate due to a higher equity ratio and lower short-term borrowings. These increases were partially offset by $3 million and $11 million in the third quarter and year-to-date 2017, respectively, of revenues and expenses, net from unregulated sales of products and services. In 2018, these revenues and expenses are included in other revenues and
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


other operations and maintenance expenses, respectively, as a result of the adoption of ASC 606. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.
Income Taxes
Third Quarter 2018 vs. Third Quarter 2017
Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)
(% change)
(change in millions) (% change)
$(88)
(25.1)
$(493) (69.9)
In the third quarter 2018, income taxes were $262 million compared to $350 million in the corresponding period in 2017. For year-to-date 2018, income taxes were $212 million compared to $705 million in the corresponding period in 2017. The decreases were primarily due to a lower federal income tax rate as a result of the Tax Reform Legislation, partially offset by the recognition of a valuation allowance on certain state tax credit carryforwards. Also contributing to the decrease for year-to-date 2018 was the reduction in pre-tax earnings resulting from the estimated probable loss related to Plant Vogtle Units 3 and 4.
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. Also, see Note (H) to the Condensed Financial Statements herein for additional information on the Tax Reform Legislation and the net state income tax valuation allowance.
Dividends on Preferred and Preference Stock
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(4) (100.0) $(13) (100.0)
In the third quarter and year-to-date 2018, there were no dividends on preferred and preference stock compared to $4 million and $13 million, respectively, in the corresponding periods in 2017. The decreases were due to the redemption in October 2017 of all outstanding shares of Georgia Power's preferred and preference stock. See Note 6 to the financial statements of Georgia Power under "Outstanding Classes of Capital Stock" in Item 8 of the Form 10-K for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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 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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Georgia Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be 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).
The EPA published certain amendments to the CCR Rule, which became 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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. However, the Georgia Department of Natural Resources has not incorporated these amendments into its state CCR rule. Specific site impacts are being evaluated by Georgia Power.
On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Georgia Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
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 the ARO liability. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on the ARO liability is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power will record any necessary changes to its ARO liability. Georgia Power expects to continue to periodically update these cost estimates, which could increase 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, 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.
Nuclear Decommissioning
See Note 1 to the financial statements of Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Georgia Power's ARO liability. The ultimate outcome of these studies 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.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Georgia Power has ownership interests in 20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Georgia Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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 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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Georgia Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 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. At September 30, 2018, the related regulatory liability balance totaled $655 million. 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. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. 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.
Storm Damage Recovery
See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in the regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to the storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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, 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. 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 September 30, 2018(b)
(4.3)
Remaining estimate to complete(a)
$4.1
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.
The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.
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 only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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 Criteria (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 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 August 31, 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 as described above, the holders of at least 90% of the ownership
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC 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, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
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 Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


(either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.
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 September 30, 2018, Georgia Power had recovered approximately $1.8 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 expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and 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,
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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 $680 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 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.
The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 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.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia Power in Item 1A herein and 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
As of September 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 September 2018, the DOE extended the conditional commitment to March 31, 2019. 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. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Georgia Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power," and Note (H) to the Condensed Financial Statements herein for information regarding the EPC Contractor's bankruptcy.Tax Reform Legislation and related regulatory actions.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air qualitylaws and water standards,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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Georgia Power regularly reviews its business to transform and modernize. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and ongoing efforts to increase overall operating efficiencies, Georgia Power initiated the closure of its remaining payment offices and an employee attrition plan affecting approximately 300 positions. Charges associated with these activities did not have a material impact on Georgia Power's results of operations, financial position, or cash flows. The efficiencies gained are expected to place downward pressure on operating costs in 2018.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimatesestimates.
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 Utility Regulation, Asset Retirement Obligations, Pension$5.68 billion would be presumed to be reasonable and Other Postretirement Benefits,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 Contingent Obligations.approximately $188 million in related Customer Refunds) 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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 approximately $188 million in related Customer Refunds). 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 did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast in the nineteenth VCM report filed with the Georgia PSC 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 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 only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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. 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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.
information regarding ASU No. 2016-02, In 2014,Leases (Topic 842) (ASU 2016-02). See Note (A) to the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidanceCondensed Financial Statements herein for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosuresinformation regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Georgia Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.recently adopted accounting standards.
Georgia Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Georgia Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Georgia Power intends to use the modified retrospective method of adoption effective January 1, 2018. Georgia Power has
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Georgia Power's financial statements, Georgia Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017,2016, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving2016-02, which requires lessees to recognize on the Presentationbalance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of Net Periodic Pension Costexpense associated with leases and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer reportprovides clarification regarding the service cost component in the same line item or items as other compensation costs and requires the otheridentification of certain components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost componentcontracts that would represent a lease. The accounting required by lessors is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations.relatively unchanged. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Georgia Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Georgia Power's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 2017-122016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlyGeorgia Power will adopt the new standard effective January 1, 2019.
Georgia Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption permitted. date of January 1, 2019, without restating prior periods. Georgia Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Georgia Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Georgia Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Georgia Power is evaluatingcontinuing to complete the standardimplementation of an information technology system to track and expectsaccount for its leases and of changes to early adoptits internal controls and accounting policies to support the accounting for leases under ASU 2017-12 effective January 1, 2018. The2016-02. Georgia Power has substantially completed its lease inventory and determined its most significant leases involve PPAs and real estate. While Georgia Power has not yet determined the ultimate impact, adoption of ASU 2017-122016-02 is not expected to have aresult in recording lease liabilities and right-of-use assets on Georgia Power's balance sheet each totaling approximately $1.8 billion, with no material impact on Georgia Power's financial statements.statement of income.
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 September 30, 2017.2018. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.48$2.23 billion for the first nine months of 20172018 compared to $2.27$1.48 billion for the corresponding period in 2016.2017. The decreaseincrease was primarily due to the timing of vendor and property tax payments, and fossil fuel stock purchases and an increasea decrease in under-recovered fuel costs. Net cash used for investing activities totaled $1.83 billion for the first nine months of 2017 compared to $1.76 billion for the corresponding period in 2016 primarilycurrent income taxes related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $617 million for the first nine months of 2017 compared to $528 million used for financing activities in theTax Reform Legislation, income tax refunds
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


corresponding period in 2016. The increase in cash provided from financing activities is primarily due to an increase in short-term borrowings, higher issuancesreceived, increased fuel cost recovery, and the timing of senior notes and junior subordinated notes, and a decrease in maturities of senior notes,fossil fuel stock purchases, partially offset by a decrease in borrowings frompayments of customer refunds primarily related to the FFBGuarantee Settlement Agreement. Net cash used for investing activities totaled $2.21 billion for the first nine months of 2018 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including $0.9 billion related to the construction of Plant Vogtle Units 3 and 44. Net cash used for financing activities totaled $492 million for the first nine months of 2018 primarily due to payments of common stock dividends, the redemption and an increase in redemptionsrepurchase of short-term borrowings.senior notes, and pollution control revenue bond purchases, partially offset by capital contributions from Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 20172018 include increasesan increase of $1.2$2.3 billion in paid-in capital primarily due to capital contributions received from Southern Company, a decrease of $1.6 billion in long-term debt (including securities due within one year) primarily due to the redemption and repurchase of senior notes and the purchase of pollution control revenue bonds, and an increase of $0.5 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, $1.2net of the $1.1 billion in long-term debt primarily due to issuances of senior notes and junior subordinated notes, $423 million in accounts payable, other primarily due to charges for restoration costs related to Hurricane Irma and liabilities for the removal of subcontractor lienscharge related to the EPC Contractor's bankruptcy,construction of Plant Vogtle Units 3 and $423 million in paid-in capital primarily due4. See Note (B) to capital contributions received from Southern Company. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Recovery" and " – Nuclear Construction"the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Hurricane IrmaPlant Vogtle Units 3 and the EPC Contractor's bankruptcy, respectively.4.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements.contractual obligations. Approximately $261$511 million will be required through September 30, 20182019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
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 pending 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 fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.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, short-term debt, external security issuances, term loans,borrowings from financial institutions, equity contributions from Southern Company, and to the extent available, borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval,approvals, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
In 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding)Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2017,2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. OnIn July 27, 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.
OnIn September 28, 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 March 31, 2019, 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. 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 (E)(F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At September 30, 2017,2018, Georgia Power's current liabilities exceeded current assets by $698$552 million primarily due to long-term debt that is due within one year of $511 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt ($261 million at September 30, 2017) and the periodic use of short-term debt as a funding source, ($400 million at September 30, 2017), as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans,borrowings from financial institutions, and equity contributions from Southern
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Company and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At September 30, 2017,2018, Georgia Power had approximately $266$380 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks was $1.75 billion at September 30, 2017 was $1.75 billion2018, of which $1.73$1.74 billion was unused. In May 2017, Georgia Power amended its multi-yearThis credit arrangement which, among other things, extended the maturity date from 2020 toexpires in 2022.
This bank credit arrangement as well as Georgia Power's term loan arrangements, 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 September 30, 2017,2018, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(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 outstanding requiring liquidity support as of September 30, 20172018 was approximately $550 million as compared to $868 million at December 31, 2016. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


credit arrangement.million. In addition, at September 30, 2017,2018, Georgia Power had $509$345 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
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. Commercial paper isShort-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
  Short-term Debt at September 30, 2017 
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 $—
 —% $109
 1.5% $428
Short-term bank debt 400
 2.0% 568
 2.0% 800
Total $400
 2.0% $677
 2.0%  
 Short-term Debt at September 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$102
 2.4% $260
 2.3% $480
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.2018.
Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
At September 30, 2017,2018, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and transmission.construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 20172018 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements		Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$87
$87
Below BBB- and/or Baa3$1,021
$1,025
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (affiliate company of Georgia Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
On March 20, 2017,February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A. On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Georgia Power).
On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3. On September 28, 2018, Moody's revised its rating outlook for Georgia Power from stablenegative to negative.stable.
On March 24, 2017, S&P revised its consolidatedAs a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating outlook foragencies to assess Southern Company and its subsidiaries, (includingincluding Georgia Power) from stablePower, may be negatively impacted. The Tax Reform Settlement Agreement approved by the Georgia PSC on April 3, 2018 is expected to negative.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, which is scheduled to be filed by July 1, 2019. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Rate Plans" herein for additional information.
Financing Activities
In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
In 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.
During 2018, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In March 2017, Georgia Power issued $450$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.2009
In April 2017, Georgia Power purchased and held $27$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.1994
In June 2017, Georgia Power repaid at maturity $450$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2007B 5.70% Senior Notes.2008
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
Also in August 2017, Georgia Power purchased and held $38$71.735 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.
In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.2013
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.

Table of Contents

GULF POWER COMPANY

Table of Contents

GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017
2016 2017 20162018
2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$375
 $377
 $972
 $978
$341
 $375
 $932
 $972
Wholesale revenues, non-affiliates14
 17
 44
 48
15
 14
 41
 44
Wholesale revenues, affiliates28
 23
 75
 59
40
 28
 83
 75
Other revenues20
 19
 53
 51
18
 20
 50
 53
Total operating revenues437
 436
 1,144
 1,136
414
 437
 1,106
 1,144
Operating Expenses:              
Fuel127
 141
 323
 342
132
 127
 305
 323
Purchased power, non-affiliates37
 33
 104
 95
Purchased power, affiliates2
 3
 13
 9
Purchased power44
 38
 135
 116
Other operations and maintenance81
 86
 252
 239
82
 84
 248
 260
Depreciation and amortization42
 49
 95
 129
48
 42
 142
 95
Taxes other than income taxes33
 34
 88
 93
33
 33
 91
 88
Loss on Plant Scherer Unit 3—
 —
 33
 —
—
 —
 —
 33
Total operating expenses322
 346
 908
 907
339
 324
 921
 915
Operating Income115
 90
 236
 229
75
 113
 185
 229
Other Income and (Expense):              
Interest expense, net of amounts capitalized(13) (11) (37) (36)(13) (13) (39) (37)
Other income (expense), net1
 (2) —
 (4)(3) 3
 —
 7
Total other income and (expense)(12) (13) (37) (40)(16) (10) (39) (30)
Earnings Before Income Taxes103
 77
 199
 189
59
 103
 146
 199
Income taxes40
 30
 78
 74
Income taxes (benefit)(4) 40
 (1) 78
Net Income63
 47
 121
 115
63
 63
 147
 121
Dividends on Preference Stock—
 2
 4
 7
—
 —
 —
 4
Net Income After Dividends on Preference Stock$63
 $45
 $117
 $108
$63
 $63
 $147
 $117
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Net Income$63
 $47
 $121
 $115
$63
 $63
 $147
 $121
Other comprehensive income (loss):              
Qualifying hedges:              
Changes in fair value, net of tax of $-, $-, $(1), and $(3), respectively—
 —
 (1) (4)
Changes in fair value, net of tax of
$-, $-, $-, and $(1), respectively		—
 —
 —
 (1)
Total other comprehensive income (loss)—
 —
 (1) (4)—
 —
 —
 (1)
Comprehensive Income$63
 $47
 $120
 $111
$63
 $63
 $147
 $120
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

Table of Contents

GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$147
 $121
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total147
 100
Deferred income taxes(45) 57
Loss on Plant Scherer Unit 3—
 33
Other, net(10) (5)
Changes in certain current assets and liabilities —   
-Receivables(5) (65)
-Other current assets9
 18
-Accrued taxes35
 21
-Accrued compensation(9) (10)
-Over recovered regulatory clause revenues39
 (8)
-Other current liabilities10
 10
Net cash provided from operating activities318
 272
Investing Activities:   
Property additions(207) (142)
Cost of removal, net of salvage(18) (16)
Change in construction payables5
 (9)
Other investing activities(18) (6)
Net cash used for investing activities(238) (173)
Financing Activities:   
Increase (decrease) in notes payable, net5
 (268)
Proceeds —   
Common stock issued to parent—
 175
Capital contributions from parent company40
 7
Senior notes—
 300
Redemptions —   
Preference stock—
 (150)
Senior notes—
 (85)
Payment of common stock dividends(115) (94)
Other financing activities(1) (3)
Net cash used for financing activities(71) (118)
Net Change in Cash, Cash Equivalents, and Restricted Cash9
 (19)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period28
 56
Cash, Cash Equivalents, and Restricted Cash at End of Period$37
 $37
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $- and $- capitalized for 2018 and 2017, respectively)$26
 $24
Income taxes, net28
 19
Noncash transactions — Accrued property additions at end of period31
 25
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

Table of Contents

GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $37
 $28
Receivables —    
Customer accounts receivable 100
 76
Unbilled revenues 69
 67
Under recovered regulatory clause revenues —
 27
Affiliated 20
 14
Other 5
 7
Accumulated provision for uncollectible accounts (1) (1)
Fossil fuel stock 58
 63
Materials and supplies 61
 57
Other regulatory assets, current 47
 56
Other current assets 13
 21
Total current assets 409
 415
Property, Plant, and Equipment:    
In service 5,313
 5,196
Less: Accumulated provision for depreciation 1,540
 1,461
Plant in service, net of depreciation 3,773
 3,735
Construction work in progress 152
 91
Total property, plant, and equipment 3,925
 3,826
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 30
 31
Other regulatory assets, deferred 495
 502
Other deferred charges and assets 46
 23
Total deferred charges and other assets 571
 556
Total Assets $4,905
 $4,797
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 Nine Months Ended September 30,
 2017 2016
 (in millions)
Operating Activities:   
Net income$121
 $115
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total100
 134
Deferred income taxes57
 15
Loss on Plant Scherer Unit 333
 —
Other, net(5) (2)
Changes in certain current assets and liabilities —   
-Receivables(65) (9)
-Fossil fuel stock7
 49
-Other current assets11
 3
-Accrued taxes21
 40
-Accrued compensation(10) (5)
-Over recovered regulatory clause revenues(8) 26
-Other current liabilities10
 8
Net cash provided from operating activities272
 374
Investing Activities:   
Property additions(142) (106)
Cost of removal, net of salvage(16) (8)
Change in construction payables(9) (7)
Other investing activities(6) (6)
Net cash used for investing activities(173) (127)
Financing Activities:   
Decrease in notes payable, net(268) (42)
Proceeds —   
Common stock issued to parent175
 —
Capital contributions from parent company7
 10
Senior notes300
 —
Redemptions —   
Preference stock(150) —
Senior notes(85) (125)
Payment of common stock dividends(94) (90)
Other financing activities(3) (5)
Net cash used for financing activities(118) (252)
Net Change in Cash and Cash Equivalents(19) (5)
Cash and Cash Equivalents at Beginning of Period56
 74
Cash and Cash Equivalents at End of Period$37
 $69
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $- and $- capitalized for 2017 and 2016, respectively)$24
 $29
Income taxes, net19
 14
Noncash transactions — Accrued property additions at end of period25
 13
The accompanying notes as they relate to Gulf Power are an integral partTable of these condensed financial statements.Contents

GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30, 2017 At December 31, 2016
  (in millions)
Current Assets:    
Cash and cash equivalents $37
 $56
Receivables —    
Customer accounts receivable 96
 72
Unbilled revenues 68
 55
Under recovered regulatory clause revenues 15
 17
Income taxes receivable, current 15
 —
Other accounts and notes receivable 12
 6
Affiliated 13
 17
Accumulated provision for uncollectible accounts (1) (1)
Fossil fuel stock 64
 71
Materials and supplies 58
 55
Other regulatory assets, current 55
 44
Other current assets 15
 30
Total current assets 447
 422
Property, Plant, and Equipment:    
In service 5,181
 5,140
Less: Accumulated provision for depreciation 1,457
 1,382
Plant in service, net of depreciation 3,724
 3,758
Construction work in progress 75
 51
Total property, plant, and equipment 3,799
 3,809
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 56
 58
Other regulatory assets, deferred 499
 512
Other deferred charges and assets 22
 21
Total deferred charges and other assets 577
 591
Total Assets $4,823
 $4,822
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 September 30, 2017 At December 31, 2016 At September 30, 2018 At December 31, 2017
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $7
 $87
Notes payable —
 268
 $50
 $45
Accounts payable —        
Affiliated 46
 59
 64
 52
Other 55
 54
 67
 75
Customer deposits 35
 35
 35
 35
Accrued taxes 41
 20
 45
 10
Accrued interest 20
 8
 20
 9
Accrued compensation 30
 40
 30
 39
Deferred capacity expense, current 22
 22
 22
 22
Asset retirement obligations, current 43
 37
Other regulatory liabilities, current 1
 16
 69
 —
Other current liabilities 37
 40
 20
 27
Total current liabilities 294
 649
 465
 351
Long-term Debt 1,285
 987
 1,285
 1,285
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 1,003
 948
 542
 537
Deferred credits related to income taxes 380
 458
Employee benefit obligations 90
 96
 96
 102
Deferred capacity expense 103
 119
 81
 97
Asset retirement obligations, deferred 125
 120
 121
 105
Other cost of removal obligations 218
 249
 218
 221
Other regulatory liabilities, deferred 45
 47
 51
 43
Other deferred credits and liabilities 71
 71
 62
 67
Total deferred credits and other liabilities 1,655
 1,650
 1,551
 1,630
Total Liabilities 3,234
 3,286
 3,301
 3,266
Preference Stock —
 147
Common Stockholder's Equity:        
Common stock, without par value —        
Authorized — 20,000,000 shares        
Outstanding — September 30, 2017: 7,392,717 shares    
— December 31, 2016: 5,642,717 shares 678
 503
Outstanding — 7,392,717 shares 678
 678
Paid-in capital 600
 589
 636
 594
Retained earnings 312
 296
 291
 259
Accumulated other comprehensive income (loss) (1) 1
Accumulated other comprehensive loss (1) —
Total common stockholder's equity 1,589
 1,389
 1,604
 1,531
Total Liabilities and Stockholder's Equity $4,823
 $4,822
 $4,905
 $4,797
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 20172018 vs. THIRD QUARTER 20162017
AND
YEAR-TO-DATE 20172018 vs. YEAR-TO-DATE 20162017


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 $1.3 billion), subject to certain adjustments. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions. 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.
OnAs a continuation of a settlement agreement approved by the Florida PSC in April 4, 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respectaddressing 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 requestrevenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to increase retail base rates. Amongnormalization) deferred tax liabilities through a reduced fuel cost recovery rate over the termsremainder of 2018. Through September 30, 2018, approximately $53 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. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
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.
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to the property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved bycan petition the Florida PSC to seek recovery of the costs associated with
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. The ultimate outcome of this matter cannot be determined at this time. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in November 2016.Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Cost Recovery" herein 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 after dividends on preference stock.income.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$18 40.0 $9 8.3
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$— — $30 25.6
Gulf Power's net income after dividends on preference stock for the third quarter 2017 was $63 million compared to $45 million for2018 and the corresponding period in 2016. The increase2017 was primarily due to an increase$63 million. Net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, substantially offset by a reduction in retail base revenues and a decrease in depreciation.related to the Gulf Power Tax Reform Settlement Agreement.
Gulf Power's net income after dividends on preference stock for year-to-date 20172018 was $117$147 million compared to $108$117 million for the corresponding period in 2016.2017. The increase was primarily due to higher retail base revenues effective July 2017 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 decreaseresult of the Tax Reform Legislation, partially offset by a reduction in depreciation andretail 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
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(34) (9.1) $(40) (4.1)
In the third quarter 2018, retail revenues were $341 million compared to $375 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $932 million compared to $972 million for the corresponding period in 2017.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

an increase in retail base revenues, partially offset by a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement and higher operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
Retail Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(2) (0.5) $(6) (0.6)
In the third quarter 2017, retail revenues were $375 million compared to $377 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $972 million compared to $978 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
Third Quarter 2017 Year-to-Date 2017Third Quarter 2018 Year-to-Date 2018
(in millions) (% change) (in millions) (% change)(in millions) (% change) (in millions) (% change)
Retail – prior year$377
   $978
  $375
   $972
  
Estimated change resulting from –              
Rates and pricing21
 5.6
 28
 2.9
(35) (9.3) (51) (5.2)
Sales growth3
 0.8
 1
 0.1
Sales growth (decline)(2) (0.6) 2
 0.2
Weather(9) (2.4) (14) (1.4)6
 1.6
 16
 1.6
Fuel and other cost recovery(17) (4.5) (21) (2.2)(3) (0.8) (7) (0.7)
Retail – current year$375
 (0.5)% $972
 (0.6)%$341
 (9.1)% $932
 (4.1)%
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increaseddecreased in the third quarter and year-to-date 20172018 when compared to the corresponding periods in 20162017 primarily due to a decrease in revenues effective January 1, 2018 due to the Gulf Power Tax Reform Settlement Agreement. In addition, the year-to-date 2018 amounts were partially offset by an increase in retail base revenuesrates effective July 2017 as well as an increase in environmental cost recovery effective November 2016accordance with the 2017 Gulf Power Rate Case Settlement Agreement.
Revenues attributable to changes in sales decreased in the third quarter 2018 when compared to the corresponding period in 2017. For the third quarter 2018, weather-adjusted KWH sales to residential customers decreased 3.9% due to lower customer usage, primarily resulting from Gulf Power's ownership of Plant Scherer Unit 3 being rededicatedefficiency improvements, partially offset by customer growth. Weather-adjusted KWH sales to retail service.commercial customers decreased 2.5% primarily due to lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers increased 4.8% for the third quarter 2018 primarily due to decreased customer cogeneration levels and other changes in customers' operations.
Revenues attributable to changes in sales increased slightly in the third quarter andfor year-to-date 20172018 when compared to the corresponding periodsperiod in 2016.2017. For the third quarter 2017,year-to-date 2018, weather-adjusted KWH sales to residential and commercial customers increased 5.2% and 1.5%, respectively. Weather-adjusted KWH sales to residential customers increased 1.3% year-to-date 2017. These increases were primarilyessentially flat due to customer growth, partially offset by lower customer usage, primarily resulting from efficiency improvements, in appliances and lighting.offset by customer growth. Weather-adjusted KWH sales to commercial customers decreased slightly year-to-date 2017 as a result of0.7% primarily due to lower customerenergy usage primarily resulting from energy efficiency improvements in appliances and lighting, mostly offset by customer growth.lighting. KWH sales to industrial customers decreased 7.1% and 6.1% for the third quarter andincreased 1.3% year-to-date 2017, respectively,2018 primarily due to changes in customers' operations and energy efficiency improvements.customer cogeneration levels.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 20172018 when compared to the corresponding periodsperiod in 2016,2017, primarily due to lower recoverable costs under the fuel cost recovery clause. 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 energy conservation recoverable costs, partially offset by higher environmental recoverable costs.fuel cost recovery clauses. Fuel and other cost recovery
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Note (B) to the Condensed Financial Statements under2017 Gulf Power Rate Case Settlement Agreement, respectively. Also see FUTURE EARNINGS
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

POTENTIAL – "Retail Regulatory Matters – Gulf Power – Retail Base Rate CasesCase" herein for additional information regarding the 2017 Rate CaseGulf Power Tax Reform Settlement Agreement.
Wholesale Revenues – Non-Affiliates
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(3) (17.6) $(4) (8.3)
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 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.
In the third quarter 2017, wholesale revenues from sales to non-affiliates were $14 million compared to $17 million for the corresponding period in 2016. The decrease was primarily due to a 28.4% decrease in KWH sales attributable to decreased market demand for energy as a result of milder weather.
For year-to-date 2017, wholesale revenues from sales to non-affiliates were $44 million compared to $48 million for the corresponding period in 2016. The decrease was primarily due to a 20.9% decrease in capacity revenues resulting from the expiration of a Plant Scherer Unit 3 long-term sales agreement in 2016.
Wholesale Revenues – Affiliates
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$5 21.7 $16 27.1
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$12 42.9 $8 10.7
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.
In the third quarter 2017,2018, wholesale revenues from sales to affiliates were $28$40 million compared to $23$28 million for the corresponding period in 2016.2017. The increase was primarily due to a 24.1%31.6% increase in KWH sales primarily resulting from outagesincreased generation to serve territorial load driven by warmer weather in the third quarter 2018 and a 7.9% increase in the price of affiliate generation resources.energy sold to affiliates attributable to increased sales during peak load hours.
For year-to-date 2017,2018, wholesale revenues from sales to affiliates were $75$83 million compared to $59$75 million for the corresponding period in 2016.2017. The increase was primarily due to a 19.5%24.5% increase in the price of energy sold due to dispatching higher-priced generating resources driven by the colder weather in January 2018 and warmer weather in the third quarter 2018. Partially offsetting this increase was an 11.3% decrease in KWH sales as a result of theprimarily resulting from lower availability of lower-costdue to planned outages at Gulf Power generation resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

generating units in the first half of 2018.
Fuel and Purchased Power Expenses
Third Quarter 2017
vs.
Third Quarter 2016		 Year-to-Date 2017
vs.
Year-to-Date 2016		Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$(14) (9.9) $(19) (5.6)$5
 3.9 $(18) (5.6)
Purchased power – non-affiliates4
 12.1
 9
 9.5
Purchased power – affiliates(1) (33.3) 4
 44.4
Purchased power6
 15.8 19
 16.4
Total fuel and purchased power expenses$(11)   $(6)  $11
 $1
  
In the third quarter 2017,2018, total fuel and purchased power expenses were $166$176 million compared to $177$165 million for the corresponding period in 2016.2017. The decreaseincrease was primarily the result of a $7$21 million net decrease due to the lower average cost of fuel and a $6 million net decreaseincrease related to the volume of KWHs generated and purchased, partially offset by a $10 million decrease related to the lower average cost of fuel and purchased power due to milder weather in 2017 reducing demand.lower natural gas prices.
For year-to-date 2017,2018, total fuel and purchased power expenses were $440 million compared to $446$439 million for the corresponding period in 2016.2017. The decreaseincrease was primarily the result of a $19$31 million net decreaseincrease related to the volume of KWHs generated and purchased, due to milder weather in 2017 reducing demand, partially offset by a $12$30 million net increasedecrease related to the higherlower average cost of fuel and purchased power.power resulting from lower natural gas prices.
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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of Gulf Power's generation and purchased power were as follows:
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in millions of KWHs)
2,780 2,775 7,000 6,6542,992 2,780 7,002 7,000
Total purchased power (in millions of KWHs)
1,686 1,906 4,362 5,2952,016 1,686 4,997 4,362
Sources of generation (percent) –
  
Coal59 68 55 5761 59 53 55
Gas41 32 45 4339 41 47 45
Cost of fuel, generated (in cents per net KWH) –
  
Coal3.04 3.55 3.15 3.803.06 3.04 3.12 3.15
Gas3.71 4.38 3.60 4.063.40 3.71 3.25 3.60
Average cost of fuel, generated (in cents per net KWH)
3.31 3.81 3.35 3.913.19 3.31 3.18 3.35
Average cost of purchased power (in cents per net KWH)(*)
4.32 3.79 4.70 3.513.99 4.32 4.33 4.70
(*)Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2017,2018, fuel expense was $127$132 million compared to $141$127 million for the corresponding period in 2016.2017. The decreaseincrease was primarily due to a 13.1%7.6% increase in the volume of KWHs generated primarily to serve higher territorial load driven by warmer weather, partially offset by a 3.6% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by a 29.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

prices.
For year-to-date 2017,2018, fuel expense was $323$305 million compared to $342$323 million for the corresponding period in 2016.2017. The decrease was primarily due to a 14.3%5.1% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by a 10.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.prices.
Purchased Power – Non-Affiliates
In the third quarter 2017,2018, purchased power expense from non-affiliates was $37$44 million compared to $33$38 million for the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates2017. The increase was $104 million compared to $95 million for the corresponding period in 2016. These increases were primarily due to increases of 16.3% and 35.9% for the third quarter and year-to-date 2017, respectively, in the average cost per KWH purchased, partially offset by decreases of 11.1% and 20.2% for the third quarter and year-to-date 2017, respectively,a 19.6% increase in the volume of KWHs purchased due to higher territorial load driven by warmer weather, partially offset by a 7.6% decrease in the average cost of purchased power due to lower natural gas prices.
For year-to-date 2018, purchased power expense was $135 million compared to $116 million for the corresponding period in 2017. The increase was primarily due to a 14.6% increase in the volume of KWHs purchased primarily due to higher territorial load.load driven by colder weather in January 2018 and warmer weather in the third quarter 2018, partially offset by a 7.9% 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.
Purchased Power – Affiliates
In the third quarter 2017, purchased power expense from affiliates was $2 million compared to $3 million for the corresponding period in 2016. The decrease was primarily due to a 38.3% decrease in the average cost per KWH purchased primarily resulting from lower priced power pool resources and a 20.5% decrease in the volume of KWHs purchased due to lower territorial load.
For year-to-date 2017, purchased power expense from affiliates was $13 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a 13.2% increase in the volume of KWHs purchased due to more planned outages for Gulf Power generation resources and a 29.3% increase in the average cost per KWH purchased primarily due to increased natural gas prices.
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 Affiliate purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(5) (5.8) $13 5.4
In the third quarter 2017, other operations and maintenance expenses were $81 million compared to $86 million for the corresponding period in 2016. The decrease was primarily due to lower employee compensation and benefits, including pension costs, and the suspension of the property damage reserve accrual in accordance with the 2017 Rate Case Settlement Agreement.
For year-to-date 2017, other operations and maintenance expenses were $252 million compared to $239 million for the corresponding period in 2016. The increase was primarily due to higher expenses at generation facilities associated with routine and planned maintenance.
See Note (A) to the Condensed Financial Statements under "Property Damage Reserve" herein for additional information regarding Gulf Power's property damage reserve accrual suspension and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

DepreciationOther Operations and AmortizationMaintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
Third Quarter 2018 vs. Third Quarter 2017Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change) (% change) (change in millions) (% change)
$(7)(2) (14.3) $(34) (26.4) (2.4) $(12) (4.6)
In the third quarter 2017, depreciationFor year-to-date 2018, other operations and amortization was $42maintenance expenses were $248 million compared to $49$260 million for the corresponding period in 2016. For year-to-date 2017,2017. The decrease was primarily due to decreases of $11 million in planned and routine generation maintenance expenses, including environmental expenditures, $3 million in energy service expenses, and $6 million in employee compensation and 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
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 14.3 $47 49.5
In the third quarter 2018, depreciation and amortization was $95$48 million compared to $129$42 million for the corresponding period in 2016. These decreases were2017. The increase was primarily due to changesan increase in depreciation rates as authorized by the reductions2017 Gulf Power Rate Case Settlement Agreement.
For year-to-date 2018, depreciation and amortization was $142 million compared to $95 million for the corresponding period in 2017. The increase was primarily due to an increase in depreciation rates as authorized by the 2017 Gulf Power Rate Case Settlement Agreement and depreciation credits of $34 million recognized in year-to-date 2017 as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), of $6 million and $34 million in the third quarter and year-to-date 2017, respectively, compared to the corresponding periods in 2016.2013. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case"Cases" in Item 8 of the Form 10-K for additional information.
Loss on Plant Scherer Unit 3
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.
Income Taxes (Benefit)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(44) (110.0) $(79) (101.3)
In the third quarter 2018, income tax benefit was $4 million compared to tax expense of $40 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $1 million compared to income tax expense of $78 million for the corresponding period in 2017. The changes were primarily due to the reduction in the
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

federal income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation as well as lower pre-tax earnings.
See Note (B)(H) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail BaseEffective Tax Rate Cases" herein for additional information.
Income Taxes
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$10 33.3 $4 5.4
In Also see Note 3 to the third quarter 2017, income taxes were $40 million compared to $30 million for the corresponding periodfinancial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in 2016. For year-to-date 2017, income taxes were $78 million compared to $74 million for the corresponding period in 2016. These increases were primarily due to higher pre-tax earnings.
Dividends on Preference Stock
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(2) N/M $(3) (42.9)
N/M - Not meaningful
In the third quarter 2017, there were no dividends on preference stock compared to $2 million for the corresponding period in 2016. For year-to-date 2017, dividends on preference stock were $4 million compared to $7 million for the corresponding period in 2016. These decreases were the resultItem 8 of the redemption of all preference stock in June 2017. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" hereinForm 10-K for additional information.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.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. Current proposals related to
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. 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 $1.3 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 expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iii) other customary closing conditions. 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
ComplianceGulf 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 GHG strategies to assess upcoming requirements and compliance costs relatedassociated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to federal and statecomply with environmental statuteslaws 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

implementation of requirements, the availability and cost of any deployed 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 retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts.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. The full impact of any such legislative or regulatory changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higherincreased costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity, as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. 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.information, including a discussion on the State of Florida's statutory provisions on environmental cost recovery.
Environmental StatutesLaws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws 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 effluent guidelinesrulemaking 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 final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these mattersany legal challenges and cannot be determined at this time.
Global Climate IssuesCoal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues"Environmental Laws and Regulations – Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information.information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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.
On March 28, 2017,October 15, 2018, the U.S. President signed an executive order directing agenciesCourt of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to review actionsregulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA will issue a series of rulemakings to reviewaddress this court action. Gulf Power is evaluating the Clean Power Planextent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescindany legal challenges are finalized.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

those rules. On October 16, 2017,Georgia Power continues to perform engineering studies related to its plans to close the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiationash ponds at all of its terms.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 quantify the impacts of any increase related to a change in closure strategy and/or ongoing engineering studies for the current closure strategy, and the timing of future cash outflows is indeterminable at this time; however, the impact on the ARO liability is expected to be material. As permit applications advance, engineering studies continue, and the timing of the ash pond closure for Plant Scherer Unit 3 develops further during the fourth quarter 2018, Gulf Power will record any necessary changes to its ARO liability related to its share of Plant Scherer Unit 3. Gulf Power expects to continue to periodically update these cost estimates, which could increase 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.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Gulf Power has ownership interests in seven fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Gulf Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Gulf Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Gulf Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Gulf Power's) and Southern Power's market power proceedingproceedings related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Gulf Power's) and Southern Power's June 30,2014 and 2017 triennial updated market power analysis. Theanalyses.
On May 4, 2018, the FERC directedissued an order terminating both proceedings, finding that the traditional electric operating companies (including Gulf Power) and Southern Power to show cause within 60 days whysatisfy the FERC's standards for market-based rate authority should not be revoked in certain areas adjacent to
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

rates. On May 9, 2018, the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Gulf Power) and Southern Power expectmade the compliance filing required by the order. These proceedings are 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 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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to make a filing within the specified 60 days respondingbe material to the FERC's order.
Gulf Power's results of operations. The ultimate outcome of these mattersthis 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.
Retail Base Rate Cases
The 2013 Rate Case Settlement Agreement authorizedrecovery balance of each regulatory clause for Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, asis reported in Note (B) to the Florida PSC monthly,Condensed Financial Statements herein.
Storm Damage Cost Recovery
See Note 1 to reach the midpointfinancial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the authorized retail ROE range then in effect. For 2014 and 2015,Form 10-K for information on how Gulf Power recognized reductionsmaintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property.
On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in depreciationGulf Power's service territory. Gulf Power currently estimates the costs of $8.4repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million and $20.1to $400 million, respectively. No net reductionwhich primarily will be charged to the property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in depreciation was recorded in 2016. Through Juneits property damage reserve. In accordance with the 2017 Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effectivecan petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the first billing cycle in Julyproperty damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
Retail Base Rate Case
As a continuation of the 2017 to provide an annual overall net customer impact of approximately $54.3 million. Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved the Gulf Power Tax Reform Settlement Agreement.
The net customer impact consisted of a $62.0 million increaseGulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base revenues less an annual equivalent creditrates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of approximately $7.7$69.4 million for 2017 forthe retail portion of unprotected (not subject to
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

certain wholesale revenues to be providednormalization) deferred tax liabilities through December 2019 through the purchased power capacitya reduced fuel cost recovery clause. In addition,rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to haveTax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio offrom 52.5% to 53.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017.purposes.
As part of the Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate CaseTax Reform Settlement Agreement, also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3, whichlimited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved byinitiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in November 2016.base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
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.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Cost Recovery Clauses" herein for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On October 25, 2017,November 5, 2018, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018.2019. The net effect of the approved changes is a $63$38 million increasedecrease in annual revenues effective in January 2018,2019, the majority of which will be offset by related expense increases.decreases.
RenewablesIncome Tax Matters
In 2015,See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Gulf Power in Item 7 of the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. PurchasesForm 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under these agreements began in"Regulatory Matters – Gulf Power," and Note (H) to the summer of 2017.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 regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air qualitylaws and water standards,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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.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.
information regarding ASU No. 2016-02, In 2014,Leases (Topic 842) (ASU 2016-02). See Note (A) to the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidanceCondensed Financial Statements herein for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosuresinformation regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Gulf Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.recently adopted accounting standards.
Gulf Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Gulf Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Gulf Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power intends to use the modified retrospective method of adoption effective January 1, 2018. Gulf Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Gulf Power's financial statements, Gulf Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017,2016, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving2016-02, which requires lessees to recognize on the Presentationbalance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of Net Periodic Pension Costexpense associated with leases and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer reportprovides clarification regarding the service cost component in the same line item or items as other compensation costs and requires the otheridentification of certain components of net periodic pension and postretirement benefit
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost componentcontracts that would represent a lease. The accounting required by lessors is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations.relatively unchanged. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Gulf Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Gulf Power's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 2017-122016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlyGulf Power will adopt the new standard effective January 1, 2019.
Gulf Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption permitted. date of January 1, 2019, without restating prior periods. Gulf Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Gulf Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Gulf Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Gulf Power is evaluatingcontinuing to complete the standardimplementation of an information technology system to track and expectsaccount for its leases and of changes to early adoptits internal controls and accounting policies to support the accounting for leases under ASU 2017-12 effective January 1, 2018. The2016-02. Gulf Power has substantially completed its lease inventory and determined its most significant leases involve PPAs and real estate. While Gulf Power has not yet determined the ultimate impact, adoption of ASU 2017-122016-02 is not expected to have aresult in recording lease liabilities and right-of-use assets on Gulf Power's balance sheet each totaling approximately $200 million, with no material impact on Gulf Power's financial statements.statement of income.
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 September 30, 2017.2018. 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled $272$318 million for the first nine months of 20172018 compared to $374$272 million for the corresponding period in 2016.2017. The $102$46 million decrease in net cashincrease was primarily due to decreases related to certainincreased fuel cost recovery clauses, the timing of fossil fuel stock purchases, and a federal income tax refund received in 2016.recovery. Net cash used for investing activities totaled $173$238 million in the first nine months of 20172018 primarily due to property additions to utility plant.additions. Net cash used for financing activities totaled $118$71 million for the first nine months of 20172018 primarily due to the payment of short-term debt, redemptions of preference stock and long-term debt, and common stock dividend payments,dividends, partially offset by proceedscapital contributions from issuances of long-term debt and common stock.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 nine months of 2017 primarily reflect the financing activities described above. Other significant changes2018 include an increase of $99 million in accumulated deferred income taxesproperty, plant, and equipment primarily due to accelerated depreciationadditions at generation and repair deductionsdistribution facilities; an increase of $69 million in other regulatory liabilities, current primarily due to over recovered cost recovery balances; and a decrease of $78 million in other costdeferred credits related to income taxes primarily as a result of removal obligations, as authorized in the 2013 Rate CaseGulf Power Tax Reform Settlement Agreement. See "Financing Activities" herein and Note (B) to the Condensed Financial Statements underFUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Gulf Power – Retail Base Rate CasesCase" herein for additional information.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 for its construction program, including estimated capital expenditures to comply
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

with existing environmental statutes and regulations,contractual obligations. There are no scheduled maturities of long-term debt as well as related interest, leases, derivative obligations, purchase commitments, and trust funding requirements. Approximately $7 million will be required through September 30, 2018 to fund maturities of long-term debt.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 statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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, short-term debt, external security issuances, term loans,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 September 30, 2018, Gulf Power's current liabilities frequentlyexceeded current assets by $56 million. Gulf Power's current liabilities may exceed current assets because of scheduled maturities of long-term debt and the continuedperiodic use of short-term debt as a funding source, to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs.
Gulf Power 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, including its commercial paper program which is supported by bank credit facilities.funding needs related to Hurricane Michael. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Cost Recovery" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2017,2018, Gulf Power had approximately $37 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 20172018 were as follows:
ExpiresExpires     
Executable Term
Loans
 
Expires Within One
Year
Expires     
Executable Term
Loans
 Expires Within One Year
2017 2018 2019 2020 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
20182018 2019 2020 Total Unused 
One
Year
 
Term
Out
 
No Term
Out
(in millions)
$30
 $195
 $25
 $30
 $280
 $280
 $45
 $—
 $—
 $40
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 (E)(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 September 30, 2017,2018, Gulf Power was in compliance with all such covenants. NoneA 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MostA portion of the $280 million unused credit arrangements with banks areis 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 September 30, 20172018 was approximately $82 million. In addition, at September 30, 2017,2018, Gulf Power had approximately $140$58 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 inon 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 $23
 1.4% $78
  Short-term Debt at September 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 $50
 2.5% $59
 2.3% $136
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 30, 2017.2018.
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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk
At September 30, 2017,2018, 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 September 30, 20172018 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$167
$117
Below BBB- and/or Baa3$579
$423
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 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 March 24, 2017,May 21, 2018, S&P revised its consolidatedrating 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 outlook foragencies to assess Southern Company and its subsidiaries, (includingincluding Gulf Power) from stablePower, may be negatively impacted. The Gulf Power Tax Reform Settlement Agreement is expected to negative.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk
help mitigate these potential adverse impacts to Gulf Power's market risk exposure relative to interest rate changescredit metrics by allowing a maximum equity ratio of 53.5% for the third quarter and year-to-date 2017 has not changed materially comparedall retail regulatory purposes. See Note 3 to the December 31, 2016 reporting period.financial statements of Gulf Power's exposure to market volatilityPower under "Retail Regulatory Matters" in commodity fuel pricesItem 8 of the Form 10-K and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreement shifts substantially all fuel cost responsibilityNote (B) to the purchaser.
Condensed Financial Statements under "In connection with the 2017 Rate Case Settlement Agreement, Regulatory Matters – Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolved the market price risk concern around Gulf Power's uncontracted wholesale generating capacity related to Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.
For additional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.
Financing Activities
In January 2017, Gulf Power issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including Gulf Power's continuous construction program.
In March 2017, Gulf Power extendeddid not issue or redeem any securities during the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due Maynine months ended September 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock.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.

Table of Contents

MISSISSIPPI POWER COMPANY

Table of Contents

MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOMEOPERATIONS (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$243
 $263
 $665
 $652
$254
 $243
 $660
 $665
Wholesale revenues, non-affiliates72
 78
 196
 198
65
 72
 184
 196
Wholesale revenues, affiliates21
 7
 40
 23
28
 21
 81
 40
Other revenues5
 4
 14
 12
11
 5
 31
 14
Total operating revenues341
 352
 915
 885
358
 341
 956
 915
Operating Expenses:              
Fuel120
 112
 301
 268
116
 120
 312
 301
Purchased power, non-affiliates4
 3
 7
 4
Purchased power, affiliates2
 5
 13
 14
Purchased power11
 6
 27
 20
Other operations and maintenance66
 74
 206
 211
80
 68
 222
 213
Depreciation and amortization39
 30
 120
 114
42
 39
 126
 120
Taxes other than income taxes25
 31
 77
 81
28
 25
 83
 77
Estimated loss on Kemper IGCC34
 88
 3,155
 222
1
 34
 45
 3,155
Total operating expenses290
 343
 3,879
 914
278
 292
 815
 3,886
Operating Income (Loss)51
 9
 (2,964) (29)80
 49
 141
 (2,971)
Other Income and (Expense):              
Allowance for equity funds used during construction1
 31
 72
 90
—
 1
 —
 72
Interest expense, net of amounts capitalized13
 (15) (23) (46)(19) 13
 (59) (23)
Other income (expense), net(1) (1) (3) (4)—
 1
 28
 4
Total other income and (expense)13
 15
 46
 40
(19) 15
 (31) 53
Earnings (Loss) Before Income Taxes64
 24
 (2,918) 11
61
 64
 110
 (2,918)
Income taxes (benefit)24
 (2) (885) (29)14
 24
 23
 (885)
Net Income (Loss)40
 26
 (2,033) 40
47
 40
 87
 (2,033)
Dividends on Preferred Stock—
 —
 1
 1
—
 —
 1
 1
Net Income (Loss) After Dividends on Preferred Stock$40
 $26
 $(2,034) $39
$47
 $40
 $86
 $(2,034)
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Net Income (Loss)$40
 $26
 $(2,033) $40
$47
 $40
 $87
 $(2,033)
Other comprehensive income (loss)
 
 
 
Other comprehensive income (loss):
 
 
 
Qualifying hedges:              
Changes in fair value, net of tax of $-, $-, $-, and $-, respectively(1) —
 —
 (1)
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
 1
—
 —
 1
 1
Total other comprehensive income (loss)(1) —
 1
 —
—
 (1) —
 1
Comprehensive Income (Loss)$39
 $26
 $(2,032) $40
$47
 $39
 $87
 $(2,032)
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

Table of Contents

MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income (loss)$87
 $(2,033)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —   
Depreciation and amortization, total129
 144
Deferred income taxes420
 (1,159)
Allowance for equity funds used during construction—
 (72)
Estimated loss on Kemper IGCC21
 3,148
Other, net5
 (26)
Changes in certain current assets and liabilities —   
-Receivables(46) 438
-Fossil fuel stock(2) 21
-Other current assets(5) (9)
-Accounts payable(3) (21)
-Accrued taxes57
 20
-Accrued compensation(9) (12)
-Over recovered regulatory clause revenues20
 (47)
-Other current liabilities(18) (31)
Net cash provided from operating activities656
 361
Investing Activities:   
Property additions(117) (411)
Construction payables(9) (47)
Payments pursuant to LTSAs(28) (10)
Other investing activities(16) (15)
Net cash used for investing activities(170) (483)
Financing Activities:   
Decrease in notes payable, net(4) (23)
Proceeds —   
Senior notes600
 —
Short-term borrowings300
 113
Capital contributions from parent company(2) 1,002
Long-term debt to parent company—
 40
Redemptions —   
Other long-term debt(900) (300)
Short-term borrowings(300) (109)
Pollution control revenue bonds(43) —
Long-term debt to parent company—
 (591)
Other financing activities(6) (3)
Net cash provided from (used for) financing activities(355) 129
Net Change in Cash, Cash Equivalents, and Restricted Cash131
 7
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period248
 224
Cash, Cash Equivalents, and Restricted Cash at End of Period$379
 $231
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (paid $57 and $73, net of $- and $28 capitalized for 2018
and 2017, respectively)		$57
 $45
Income taxes, net(483) (209)
Noncash transactions — Accrued property additions at end of period23
 32
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

Table of Contents

MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $379
 $248
Receivables —    
Customer accounts receivable 49
 36
Unbilled revenues 43
 41
Income taxes receivable, current 3
 4
Affiliated 35
 16
Other accounts and notes receivable 47
 12
Fossil fuel stock 19
 17
Materials and supplies, current 52
 44
Other regulatory assets, current 110
 125
Other current assets 4
 9
Total current assets 741
 552
Property, Plant, and Equipment:    
In service 4,819
 4,773
Less: Accumulated provision for depreciation 1,389
 1,325
Plant in service, net of depreciation 3,430
 3,448
Construction work in progress 106
 84
Total property, plant, and equipment 3,536
 3,532
Other Property and Investments 24
 30
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 34
 35
Other regulatory assets, deferred 466
 437
Accumulated deferred income taxes —
 247
Other deferred charges and assets 16
 33
Total deferred charges and other assets 516
 752
Total Assets $4,817
 $4,866
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months Ended September 30,
 2017 2016
 (in millions)
Operating Activities:   
Net income (loss)$(2,033) $40
Adjustments to reconcile net income (loss) to net cash provided from operating activities —   
Depreciation and amortization, total144
 115
Deferred income taxes(1,159) 34
Allowance for equity funds used during construction(72) (90)
Estimated loss on Kemper IGCC3,148
 222
Other, net(26) (1)
Changes in certain current assets and liabilities —   
-Receivables438
 3
-Fossil fuel stock21
 8
-Other current assets(9) 34
-Accounts payable(21) 5
-Accrued taxes20
 96
-Accrued compensation(12) (5)
-Over recovered regulatory clause revenues(47) (20)
-Customer liability associated with Kemper refunds—
 (73)
-Other current liabilities(31) 5
Net cash provided from operating activities361
 373
Investing Activities:   
Property additions(411) (592)
Construction payables(47) (25)
Government grant proceeds—
 137
Other investing activities(25) (29)
Net cash used for investing activities(483) (509)
Financing Activities:   
Decrease in notes payable, net(23) —
Proceeds —   
Capital contributions from parent company1,002
 227
Long-term debt to parent company40
 200
Other long-term debt—
 900
Short-term borrowings113
 —
Redemptions —   
Short-term borrowings(109) (475)
Long-term debt to parent company(591) (225)
Other long-term debt(300) (425)
Other financing activities(3) (5)
Net cash provided from financing activities129
 197
Net Change in Cash and Cash Equivalents7
 61
Cash and Cash Equivalents at Beginning of Period224
 98
Cash and Cash Equivalents at End of Period$231
 $159
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (paid $73 and $72, net of $28 and $36 capitalized for 2017
and 2016, respectively)		$45
 $36
Income taxes, net(209) (231)
Noncash transactions — Accrued property additions at end of period32
 80
The accompanying notes as they relate to Mississippi Power are an integral partTable of these condensed financial statements.Contents

MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30, 2017 At December 31, 2016
  (in millions)
Current Assets:    
Cash and cash equivalents $231
 $224
Receivables —    
Customer accounts receivable 38
 29
Unbilled revenues 41
 42
Income taxes receivable, current 102
 544
Other accounts and notes receivable 15
 14
Affiliated 15
 15
Fossil fuel stock 20
 100
Materials and supplies 45
 76
Other regulatory assets, current 113
 115
Other current assets 8
 8
Total current assets 628
 1,167
Property, Plant, and Equipment:    
In service 4,836
 4,865
Less: Accumulated provision for depreciation 1,312
 1,289
Plant in service, net of depreciation 3,524
 3,576
Construction work in progress 75
 2,545
Total property, plant, and equipment 3,599
 6,121
Other Property and Investments 28
 12
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 62
 361
Other regulatory assets, deferred 436
 518
Accumulated deferred income taxes 279
 —
Other deferred charges and assets 23
 56
Total deferred charges and other assets 800
 935
Total Assets $5,055
 $8,235
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.


MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At September 30, 2017 At December 31, 2016 At September 30, 2018 At December 31, 2017
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year —    
Parent $—
 $551
Other 1,028
 78
Securities due within one year $204
 $989
Notes payable 4
 23
 —
 4
Accounts payable —        
Affiliated 56
 62
 55
 59
Other 82
 135
 90
 96
Customer deposits 16
 16
Accrued taxes 78
 99
Unrecognized tax benefits 2
 383
Accrued taxes —    
Accrued income taxes 75
 40
Other accrued taxes 74
 101
Accrued interest 16
 46
 21
 16
Accrued compensation 29
 42
 30
 39
Accrued plant closure costs 30
 35
Asset retirement obligations, current 15
 32
 41
 37
Over recovered fuel clause liabilities 4
 51
Other current liabilities 67
 20
 56
 47
Total current liabilities 1,397
 1,538
 676
 1,463
Long-term Debt 1,167
 2,424
 1,532
 1,097
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes —
 756
 193
 —
Deferred credits related to income taxes 420
 372
Employee benefit obligations 109
 115
 111
 116
Asset retirement obligations, deferred 150
 146
 136
 137
Other cost of removal obligations 175
 170
 181
 178
Other regulatory liabilities, deferred 87
 84
 75
 79
Other deferred credits and liabilities 23
 26
 17
 33
Total deferred credits and other liabilities 544
 1,297
 1,133
 915
Total Liabilities 3,108
 5,259
 3,341
 3,475
Redeemable Preferred Stock 33
 33
 33
 33
Common Stockholder's Equity:        
Common stock, without par value —        
Authorized — 1,130,000 shares        
Outstanding — 1,121,000 shares 38
 38
 38
 38
Paid-in capital 4,529
 3,525
 4,528
 4,529
Accumulated deficit (2,650) (616) (3,119) (3,205)
Accumulated other comprehensive loss (3) (4) (4) (4)
Total common stockholder's equity 1,914
 2,943
 1,443
 1,358
Total Liabilities and Stockholder's Equity $5,055
 $8,235
 $4,817
 $4,866
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 20172018 vs. THIRD QUARTER 20162017
AND
YEAR-TO-DATE 20172018 vs. YEAR-TO-DATE 20162017


OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the Kemper County energy facility, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital and operations and maintenance expenditures required for maintenance 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.
The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) betweenOn July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related entered into a settlement agreement with respect to the combined cycle2018 PEP filing and associated common facilities portion of Kemper IGCC assets previously placed in service. As requiredall unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. on August 7, 2018. Rates under the PEP Settlement Agreement, which result in approximately $21.6 million in additional revenue annually, became effective with the first billing cycle of September 2018.
On July 6, 2017,August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement to increase rates approximately $17 million annually with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018.
The PEP and ECO Plan rates are expected to continue through the conclusion of the next base rate proceeding which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case).
On May 8, 2018, the Mississippi PSC issued an order requiringto begin an operations review of Mississippi Power, which began in August 2018, with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.
On October 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron Products Company (Chevron), for Mississippi Power to establish a regulatory liability account to maintain current rates relatedcontinue providing retail service to the Kemper IGCC following the July 2017 completionChevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "General" of Mississippi Power in Item 7 of the amortization periodForm 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. Atadditional information.
As of September 30, 2017, the related regulatory liability totaled $7 million.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A."2018, Mississippi Power achieved integrated operationrecorded charges to income of both gasifiers on January 29, 2017, includingan immaterial amount for the production of electricitythird quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from syngas in both combustion turbines. During testing, the plant producedabandonment and captured CO2,related closure activities for the mine and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under whichgasifier-related assets at the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docketfacility. Additional closure costs for the purposesmine and gasifier-related assets, currently estimated to cost up to $20 million pre-tax (excluding salvage, net of pursuing a globaldismantlement 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 $2 million for the remainder of 2018, $8 million in
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

settlement2019, and $4 million annually beginning in 2020. The ultimate outcome of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i)this matter cannot be determined at a minimum, no rate increase tothis time.
On August 6, 2018, Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertaintyfiled its proposed Reserve Margin Plan (RMP), as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject torequired by the Mississippi PSC's jurisdiction, includingorder in the potential resolutiondocket established for the purposes of pursuing a global settlement of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase forcosts related to the Kemper County energy facility cost recovery(Kemper Settlement Docket). Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated withalternatives being the gasification portionstwo-year and seven-year acceleration of the plantretirement of Plant Watson Units 4 and lignite mine. In5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2017, Mississippi2021 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 recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket,proposed transmission and system reliability improvements, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to resultagreement by Alabama Power. The RMP filing also states that, in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project areMississippi PSC ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides forapproves an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation andalternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the future, file a reserve margin plan withremaining 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 Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolvingultimate outcome of this matter in January 2018.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them tocannot be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined at this time. However, if approved by the Mississippi PSC, in the Kemper IGCC Settlement Docket proceedings.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

alternatives are not expected to have any adverse impact on customer rates.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation,County energy facility, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters""Kemper County Energy Facility" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined CycleKemper County Energy Facility" herein.
In June 2017, Southern Company made equity contributions totaling $1.0 billion toMarch 2018, Mississippi Power.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 $100 million was repaid in the third quarter 2018. Mississippi Power used a portion of the proceeds from these financings to (i) prepay $300repay a $900 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay $591 million of the outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.loan.
Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
In addition to the rate recovery of the Kemper County energy facility, Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income (Loss)
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$14 53.8 $(2,073) N/M
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 17.5 $2,120 N/M
N/M - Not meaningful
Mississippi Power's net income after dividends on preferred stock for the third quarter 20172018 was $40$47 million compared to $26$40 million for the corresponding period in 2016.2017. The increase in net income was primarily due to an increase in retail revenues as a result of PEP and ECO Plan rate increases that became effective with the first billing cycle of September 2018 and lower pre-tax charges associated with the Kemper IGCC, and a decrease in interest expense, net of amounts capitalized, partially offset by an increase in income taxesoperations and decreases in retail revenuesmaintenance expenses and AFUDC equity.interest expense, net of amounts capitalized.
Mississippi Power's net lossincome after dividends on preferred stock for year-to-date 20172018 was $2.03 billion$86 million compared to net incomea loss of $39 million$2.03 billion for the corresponding period in 2016.2017. The decreaseincrease in net income was related to higher pre-tax charges associated with the Kemper IGCC.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.is primarily attributable
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

to lower pre-tax charges associated with the Kemper IGCC, partially offset by the cessation of AFUDC equity related to the Kemper IGCC in the second quarter 2017 and higher interest expense, net of amounts capitalized.
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 regarding the Kemper IGCC.
Retail Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(20) (7.6) $13 2.0
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$11 4.5 $(5) (0.8)
In the third quarter 2017,2018, retail revenues were $243$254 million compared to $263$243 million for the corresponding period in 2016.2017. For year-to-date 2017,2018, retail revenues were $665$660 million compared to $652$665 million for the corresponding period in 2016.2017.
Details of the changes in retail revenues were as follows:
 Third Quarter 2017 Year-to-Date 2017
 (in millions) (% change) (in millions) (% change)
Retail – prior year$263
   $652
  
Estimated change resulting from –       
Rates and pricing(10) (3.8) 9
 1.4
Sales growth1
 0.4
 4
 0.6
Weather(9) (3.4) (16) (2.5)
Fuel and other cost recovery(2) (0.8) 16
 2.5
Retail – current year$243
 (7.6)% $665
 2.0 %
Revenues associated with changes in rates and pricing decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily due to recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.
 Third Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Retail – prior year$243
   $665
  
Estimated change resulting from –       
Rates and pricing11
 4.5 % (3) (0.5)%
Sales growth3
 1.3
 1
 0.2
Weather2
 0.8
 12
 1.8
Fuel and other cost recovery(5) (2.1) (15) (2.3)
Retail – current year$254
 4.5 % $660
 (0.8)%
Revenues associated with changes in rates and pricing increased in year-to-date 2017the third quarter 2018 when compared to the corresponding period in 20162017 primarily due to anthe PEP and ECO Plan rate increase implementedchanges that became effective for the first billing cycle of September 2018 resulting in retail revenue increases of $4 million and $9 million, respectively. In addition, as a result of the third quarter 2016,PEP Settlement Agreement, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing, partially offset by the recognition of regulatory liabilities of $5 million and $2 million related to the equity ratio provisions of the PEP and ECO Settlement Agreements, respectively.
Revenues associated with changes in rates and pricing decreased year-to-date 2018 when compared to the corresponding period in 2017 primarily due to a decrease in annual retail revenues of $12 million for lower base rates related to the Kemper County energy facility that became effective for the first billing cycle of April 2018 and recognition in 2018 of regulatory liability as directedliabilities of $5 million and $2 million related to the equity ratio provisions of the PEP and ECO Settlement Agreements, respectively, partially offset by the Mississippi PSC in a July 6, 2017 order following full amortizationhigher retail revenues of certain regulatory assets$5 million for PEP and an ECO Plan rate decrease implementedrates that became effective with the first billing cycle of September 2018, recognition of $5 million previously reserved in connection with the 2012 PEP lookback filing as a result of the PEP Settlement Agreement, and the recognition in the secondthird quarter 2017.2017 of a $7 million regulatory liability.
See Note (B)3 to the Condensed Financial Statementsfinancial statements of Mississippi Power under "Regulatory"Retail Regulatory Matters – Mississippi PowerPerformance Evaluation Plan" and " – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Revenues attributable to changes in sales increased slightly for the third quarter 2017 whenand year-to-date 2018 compared to the corresponding periodperiods in 2016.2017. Weather-adjusted residential and commercial KWH sales to residential customers increased 2.9% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 2.4% primarily due to an unplanned outage by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers,2.7% and a decrease in the number of mid-size customers.
Revenues attributable to changes in sales increased slightly for year-to-date 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 0.8% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.7% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 1.1% primarily due to unplanned outages by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.
Fuel and other cost recovery revenues decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased1.0%,
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

respectively, in the third quarter 2018 due to increased customer usage and slight customer growth. Weather-adjusted residential KWH sales increased 1.1% year-to-date 2018 due to increased customer usage. Weather-adjusted commercial KWH sales remained relatively flat year-to-date 2018. Industrial KWH sales increased 2.0% and 0.4% for the third quarter and year-to-date 20172018, respectively, primarily due to increased usage by several large industrial customers.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2018 when compared to the corresponding periodperiods in 20162017 primarily as a result of higherlower recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(7) (9.7) $(12) (6.1)
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.
In the third quarter 2018, wholesale revenues from sales to non-affiliates were $65 million compared to $72 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to non-affiliates were $184 million compared to $196 million for the corresponding period in 2017. These decreases primarily resulted from a decrease in revenue under the Shared Services Agreement (SSA) between Mississippi Power and Cooperative Energy of $6 million and $16 million in the third quarter and year-to-date 2018, respectively, as a result of transmission revenue now being recovered under the Open Access Transmission Tariff (OATT) and included in other revenues on the statements of operations. The year-to-date 2018 decrease was partially offset by an increase in sales due to colder weather in January 2018 and warmer weather during the second and third quarters 2018.
Wholesale Revenues – Affiliates
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$14 N/M $17 73.9
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 33.3 $41 N/M
N/M - Not meaningful
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the third quarter 2017,2018, wholesale revenues from sales to affiliates were $21$28 million compared to $7$21 million for the corresponding period in 2016. The increase was due to a $13 million increase in KWH sales as a result of supporting Southern Company system transmission reliability and a $1 million increase primarily due to higher natural gas prices.
2017. For year-to-date 2017,2018, wholesale revenues from sales to affiliates were $40$81 million compared to $23$40 million for the corresponding period in 2016. The increase was2017. These increases were primarily due to higherincreases in KWH sales as a resultdue to increased availability of supportingMississippi Power's lower cost generation resources to serve the Southern Company systemsystem's territorial load in 2018 as compared to 2017.
Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 N/M $17 N/M
N/M - Not meaningful
In the third quarter 2018, other revenues were $11 million compared to $5 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $31 million compared to $14 million for the corresponding period in 2017. These increases were primarily due to increases in transmission reliabilityrevenue related to SSA customers now being recovered under the OATT of $6 million and higher natural gas prices.$16 million in the third quarter and year-to-date 2018, respectively.
Fuel and Purchased Power Expenses
Third Quarter 2017
vs.
Third Quarter 2016		 Year-to-Date 2017
vs.
Year-to-Date 2016		Third Quarter 2018
vs.
Third Quarter 2017		 Year-to-Date 2018
vs.
Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$8
 7.1 $33
 12.3$(4) (3.3) $11
 3.7
Purchased power – non-affiliates1
 33.3 3
 75.0
Purchased power – affiliates(3) (60.0) (1) (7.1)
Purchased power5
 83.3 7
 35.0
Total fuel and purchased power expenses$6
 $35
 $1
 $18
 
In the third quarter 2017,2018, total fuel and purchased power expenses were $126$127 million compared to $120$126 million for the corresponding period in 2016.2017. The increase was primarily due to a $6an $11 million increase in the volume of KWHs generated and purchased.purchased, partially offset by a $10 million decrease in the cost of natural gas and purchased power.
For year-to-date 2017,2018, total fuel and purchased power expenses were $321$339 million compared to $286$321 million for the corresponding period in 2016.2017. The increase was primarily due to a $42$39 million increase in the average cost of natural gas and purchased power, partially offset by a $4 million decrease in coal prices and a $3 million decrease in the volume of KWHs generated and purchased.purchased, partially offset by a $20 million decrease in the cost of natural gas and purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of Mississippi Power's generation and purchased power were as follows:
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in millions of KWHs)
4,453 4,255 11,542 11,5704,581 4,453 12,665 11,542
Total purchased power (in millions of KWHs)(*)
164 288 527 877348 164 781 527
Sources of generation (percent) –
        
Coal8 10 8 98 8 7 8
Gas92 90 92 9192 92 93 92
Cost of fuel, generated (in cents per net KWH) –
  
Coal3.80 4.02 3.60 4.093.51 3.80 3.50 3.60
Gas2.77 2.64 2.72 2.342.58 2.77 2.57 2.72
Average cost of fuel, generated (in cents per net KWH)
2.86 2.79 2.80 2.502.66 2.86 2.63 2.80
Average cost of purchased power (in cents per net KWH)(*)
3.74 2.59 3.78 2.043.18 3.74 3.47 3.78
(*)IncludesYear-to-date 2017 includes energy produced during the test period for the Kemper IGCC which isand accounted for in accordance with FERC guidance.
Fuel
In the third quarter 2017, total2018, fuel expense was $120$116 million compared to $112$120 million for the corresponding period in 2016.2017. The increasedecrease was due to a 2.5% increase in the average cost of fuel per KWH generated, primarily due to a 4.5% higher6.7% decrease in the cost of natural gas, andpartially offset by a 5.4%3.2% increase in the volume of KWHs generated.generated due to warmer weather in the third quarter 2018.
For year-to-date 2017, total2018, fuel expense was $301$312 million compared to $268$301 million for the corresponding period in 2016.2017. The increase was due to a 12.0% increase in the average cost of fuel per KWH generated primarily due to a 16.2% higher10.3% increase in the volume of KWHs generated due to colder weather in January 2018 and warmer weather during the second and third quarters 2018, partially offset by a 5.7% decrease in the cost of natural gas.
Purchased Power
In the third quarter 2018, purchased power expense was $11 million compared to $6 million for the corresponding period in 2017. The increase was primarily due to a $7 million increase in the volume of KWHs purchased, partially offset by a $2 million decrease in the cost of purchased power.
For year-to-date 2018, purchased power expense was $27 million compared to $20 million for the corresponding period in 2017. The increase was primarily due to a $9 million increase in the volume of KWHs purchased, partially offset by a $2 million decrease in the cost of purchased power.
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. EnergyThese purchases from affiliates are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(8) (10.8) $(5) (2.4)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$12 17.6 $9 4.2
In the third quarter 2017,2018, other operations and maintenance expenses were $66$80 million compared to $74$68 million for the corresponding period in 2016. The decrease was primarily due to a $5 million decrease in transmission and distribution expenses related to overhead line maintenance and a $4 million decrease related to decreases in employee compensation and benefits and corporate advertising.
2017. For year-to-date 2017,2018, other operations and maintenance expenses were $206$222 million compared to $211$213 million for the corresponding period in 2016.2017. The decrease wasincreases were primarily due to a $6 million decrease in transmission and distribution expenses related to overhead line maintenance and a $5 million decrease related to decreases in employee compensation and benefits and corporate advertising, partially offset by a $5 million increase associated with the Kemper IGCC in-service assets.costs
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recoveryrelated to an employee attrition plan. The year-to-date 2018 increase also reflects a $4 million increase primarily related to additional overhead line maintenance and vegetation management, offset by a $7 million decrease in expenses related to the combined cycle and associated common facilities portion of the Kemper IGCC Costs – 2015 Rate Case" herein for additional information.County energy facility.
Depreciation and Amortization
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$9 30.0 $6 5.3
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$3 7.7 $6 5.0
In the third quarter 2017,2018, depreciation and amortization was $39$42 million compared to $30$39 million for the corresponding period in 2016.2017. The increase was primarily related to $6a $3 million change in net amortization and deferrals associated with ECO Plan regulatory assets and liabilities and $3 million in depreciation related to additional plant in service.assets.
For year-to-date 2017,2018, depreciation and amortization was $120$126 million compared to $114$120 million for the corresponding period in 2016.2017. The increase was primarily related to $5 million inof depreciation related tofor additional plant in service.service and $1 million related to changes in net amortization associated with regulatory assets and liabilities.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K.10-K for additional information.
Taxes Other Than Income Taxes
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(6) (19.4) $(4) (4.9)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$3 12.0 $6 7.8
In the third quarter 2017,2018, taxes other than income taxes were $25$28 million compared to $31$25 million for the corresponding period in 2016.2017. For year-to-date 2017,2018, taxes other than income taxes were $77$83 million compared to $81$77 million for the corresponding period in 2016.2017. These decreasesincreases were primarily duerelated to a decreaseincreases in franchisead valorem taxes related to an increase in the assessed value of $5 millionproperty.
The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, $4 million for the third quarter and year-to-date 2017, respectively, as well as a decrease in payroll taxes of $1 million for the third quarter 2017.therefore, does not affect net income.
Estimated Loss on Kemper IGCC
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(54) (61.4) $2,933 N/M
N/M - Not meaningful
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(33) (97.1) $(3,110) (98.6)
Estimated probable losses on the Kemper IGCC ofwere $1 million for the third quarter 2018 and $45 million for year-to-date 2018, resulting from the abandonment and related closure activities for the mine and gasifier-related assets as compared to $34 million and $3.2 billion were recordedfor the corresponding periods in 2017 related to revisions to the third quarterestimated construction costs for, and year-to-datesubsequent suspension in June 2017 respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate disposition of the gasification portions of, the Kemper IGCC remains subjectIGCC.
See Note 3 to the financial statements of Mississippi PSC's jurisdiction, including the potential resolutionPower under "Kemper County Energy Facility" in Item 8 of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable. As a result, Mississippi Power suspended the project on June 28, 2017,Form 10-K and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.
PriorNote (B) to the project's suspension, Mississippi Power recorded lossesCondensed Financial Statements under "Kemper County Energy Facility" herein for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(1) (100.0) $(72) (100.0)
For year-to-date 2018, AFUDC equity was immaterial compared to $72 million for the corresponding period in 2017. The decrease resulted from suspension of the Kemper IGCC construction in June 2017.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(30) (96.8) $(18) (20.0)
In the third quarter 2017, AFUDC equity was $1 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $72 million compared to $90 million for the corresponding period in 2016. The decreases resulted from the Kemper IGCC project suspension in June 2017.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(28) N/M $(23) 50.0
N/M - Not meaningful
In the third quarter 2017, interest expense, net of amounts capitalized was $(13) million compared to $15 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to research and experimental (R&E) deductions. Also contributing to the decrease was a $4 million decrease in interest related to long-term debt. These decreases were partially offset by an $11 million reduction in interest capitalized following suspension of the Kemper IGCC construction.
For year-to-date 2017, interest expense, net of amounts capitalized was $23 million compared to $46 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to R&E deductions. Also contributing to the decrease was a $2 million decrease in interest related to short-term debt and a $1 million decrease in interest related to long-term debt. These decreases were partially offset by an $8 million reduction in interest capitalized following suspension of the Kemper IGCC construction and the amortization of $7 million in interest deferrals in accordance with the In-Service Asset Rate Order.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" herein for additional information.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$32 N/M $36 N/M
N/M - Not meaningful
In the third quarter 2018, interest expense, net of amounts capitalized was $19 million compared to an interest benefit of $13 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $59 million compared to $23 million for the corresponding period in 2017. The increases primarily reflect a $33 million net reduction in interest recorded in the third quarter 2017 following a settlement with the IRS related to research and experimental deductions. The year-to-date 2018 increase also reflects a reduction in AFUDC debt of $24 million related to the Kemper IGCC project suspension in June 2017, offset by decreases of $9 million in interest expense as a result of lower average outstanding debt, $8 million related to uncertain tax positions, and $7 million due to the completion of Kemper IGCC carrying cost amortization in 2017.
See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.
Other Income (Expense)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(1) (100.0) $24 N/M
N/M - Not meaningful
For year-to-date 2018, other income (expense), net was $28 million compared to $4 million for the corresponding period in 2017. The increase was 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 – Mississippi Power" herein for additional information.
Income Taxes (Benefit)
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$26 N/M $(856) N/M
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(10) (41.7) $908 102.6
N/M - Not meaningful
In the third quarter 2017,2018, income taxes were $24$14 million compared to an income tax benefit of $2$24 million for the corresponding period in 2016. For year-to-date 2017,2017. This change was primarily due to the reduction in the federal corporate income tax benefit was $885 million comparedrate as a result of the Tax Reform Legislation, partially offset by higher pre-tax earnings due to $29 millionlower estimated losses on the Kemper IGCC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2018, income taxes were $23 million compared to an income tax benefit of $885 million for the corresponding period in 2016. The changes were2017. This change was primarily due to thehigher pre-tax earnings due to lower estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.allowance. This change was partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation.
See Note (G)(H) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs including those related to the remainder of the Kemper County energy facility not included in current rates, in a timely manner during a time of increasing costs and itslimited projected demand growth over the next several years. Mississippi Power is scheduled to file the 2019 Base Rate Case in the fourth quarter 2019. Another factor is Mississippi Power's ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions.transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The new agreements are not expected to have a material impact on Mississippi Power's earnings; however, the co-generation assets located at the refinery are expected to be accounted for as a sales-type lease in accordance with the new lease accounting rules that become effective in 2019. These assets are also subject to a security interest granted to Chevron. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Mississippi Power's financial statements.
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 and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.10-K.
Environmental Matters
ComplianceMississippi Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Mississippi Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs relatedassociated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to federal and statecomply with environmental statuteslaws 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 technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Mississippi Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of MississippiAdditionally, 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 StatutesLaws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final effluent guidelinesrulemaking 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 final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
The ultimate outcome of these mattersany legal challenges and cannot be determined at this time.
Global Climate IssuesCoal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues"Environmental Laws and Regulations – Coal Combustion Residuals" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
The EPA published certain amendments to the CCR Rule, which became 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.
On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Mississippi Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.
During the nine months ended September 30, 2018, Mississippi Power recorded increases of approximately $21 million to its AROs related to the CCR Rule. Approximately $11 million of the revised cost estimates as of September 30, 2018 are based on information from feasibility studies performed on an ash pond at Plant Greene County, which 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 the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
As further analysis is performed and closure details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or useAbsent continued recovery of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power PlanARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.
On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.
financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.
In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii)
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

amortizationGlobal Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Kemper IGCC-related regulatory assets includedForm 10-K for additional information.
On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Mississippi Power has ownership interests in ratessix fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Mississippi Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Municipal and Rural Association Tariff
See Note 3 to the financial statements of Mississippi Power under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included"FERC Matters – Municipal and Rural Associations Tariff" in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing allItem 8 of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.
See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" hereinForm 10-K for additional information.
Mississippi Power expects to make an MRA filing in the fourth quarter 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 September 30, 2017,2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheetssheet was $3approximately $7 million compared to $13 millionan immaterial amount at December 31, 2016. Over-recovered2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 20172018 and December 31, 2016.2017.
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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Mississippi Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Mississippi Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Mississippi Power's) and Southern Power's market power proceedingproceedings related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's June 30,2014 and 2017 triennial updated market power analysis. Theanalyses.
On May 4, 2018, the FERC directedissued an order terminating both proceedings, finding that the traditional electric operating companies (including Mississippi Power) and Southern Power to show cause within 60 days whysatisfy the FERC's standards for market-based rate authority should not be revoked in certain areas adjacent torates. On May 9, 2018, the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Mississippi Power) and Southern Power expect to make amade the compliance filing withinrequired by the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Cooperative Energy Shared Service Agreement and PPA
Mississippi Power provides electricity to a municipality and various rural electric cooperative associations located in southeastern Mississippi, including Cooperative Energy. These generation servicesproceedings are provided under long-term contracts subject to a cost-based, FERC regulated MRA electric tariff and a long-term market-based wholesale contract.
On September 18, 2017, Mississippi Power and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA becomes effective on January 1, 2018, subject to the FERC's acceptance, and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2021.concluded.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The SSA provides Cooperative Energy Power Supply Agreement
See Note 3 to the option to decrease its usefinancial statements of Mississippi Power's generation servicesPower under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the MRAForm 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 subject to annualis unjust and cumulative capsunreasonable 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 one-year notice requirement. Injust 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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event Cooperative Energy elects to reduce these services,a refund is due and initiating an investigation and settlement procedures regarding the related reduction in Mississippi Power's revenuescurrent base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be significant through 2020.
In 2008,material to Mississippi Power entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the current PSA capacity is 86 MWs. On September 28, 2017, Mississippi Power and Cooperative Energy executed an amendment to the PSA effective October 1, 2017, increasing the capacity to 286 MWs under the PSA.
Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Mississippi Power transmission system that became effective in 2011. As a resultPower's results of the PSA amendments, Cooperative Energy and SCS are amending the terms of the NITSA to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018. This NITSA amendment remains subject to execution and acceptance by the FERC.
operations. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Retail Regulatory Matters
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates under PEP and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.
On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power, which began in August 2018, with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Renewables
Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020. The ultimate outcome of this matter cannot be determined at this time.
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 15, 2017,22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2016,2017, which reflected no surcharge or refund.
On July 27, 2018, Mississippi Power and the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for reviewMPUS entered into the PEP Settlement Agreement, which was approved by the Mississippi PSC.
On November 15, 2017, Mississippi Power is expected to make its annualPSC on August 7, 2018. Rates under the PEP filing for 2018. Retail rate adjustments under PEP are limited to 4% of annual retail revenue and are subject to Mississippi PSC approval.
The ultimate outcome of these matters cannot be determined at this time.
Energy Efficiency
On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 millionSettlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for August 2017.an increase of
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Compliance Overview Planapproximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $3 million as of September 30, 2018 and is included in other regulatory assets, deferred on the condensed balance sheet. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with the 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 is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $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 45% at September 30, 2018) to 50% by December 31, 2018. 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. As of September 30, 2018, Mississippi Power has recorded $5 million in other regulatory liabilities, deferred on the condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to PEP.
Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Energy Efficiency
On May 4, 2017,8, 2018, the Mississippi PSC approvedissued an order approving Mississippi Power's ECO Planrevised annual projected Energy Efficiency Cost Rider 2018 compliance filing, for 2017, which requested the maximum 2%increased annual increase inretail revenues by approximately $18$3 million primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $262018.
Ad Valorem Tax Adjustment
On May 8, 2018, the Mississippi PSC also 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.
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 related revenue requirementsapproximately $17 million in excessannual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with 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 are suspended until after the conclusion of the 2% maximum was deferred2019 Base Rate Case and Mississippi Power is not required to make any ECO Plan filings for inclusion2018, 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. As of September 30, 2018, filing.Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on the condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel Cost Recovery
At September 30, 2017,2018, the amount of over-recovered retail fuel costs included on theMississippi Power's condensed balance sheet in customer accounts receivable was $2approximately $13 million compared to $37$6 million under recovered at December 31, 2016.2017.
On November 15, 2017,During the fourth quarter 2018, Mississippi Power is expectedexpects to file its annual rate adjustment under the retail fuel cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.
Ad Valorem Tax Adjustment
On July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustmentoperating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.
Provision for Property Damage
On October 8, 2017, Hurricane Nate hit the Gulf Coast of Mississippi causing minor damage toshould have no significant effect on Mississippi Power's distribution infrastructure. Preliminary storm damage repair costs have been estimated to be immaterial. These costs may be charged to the retail property damage reserve and addressed in a subsequent System Restoration Rider rate filing. The ultimate outcome of this matter cannot be determined at this time.revenues or net income, but will affect cash flow.
Integrated Coal Gasification Combined CycleKemper County Energy Facility
SeeFor additional information on the Kemper County energy facility, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of10-K.
As the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increasemining permit holder for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Rate Recovery of Kemper IGCC Costs
Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
Kemper IGCC Settlement Docket
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.
In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.
As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition toMine reclamation began in the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred.first quarter 2018. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 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 $20 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, Mississippi Power constructed the CO2 pipelineperiod costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the planned transportmine and gasifier-related assets, are estimated at $2 million for the remainder of captured CO2 for use2018, $8 million in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury)2019, and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC$4 million annually beginning in service by July 1, 2017.
2020. The ultimate outcome of these mattersthis matter cannot be determined at this time.
TerminationThe combined cycle and associated common facilities portions of Proposed Sale of Undivided Interestthe Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
In 2010 and as amended in 2012,Reserve Margin Plan
On August 6, 2018, Mississippi Power and Cooperative Energy (formerly knownfiled its proposed RMP, as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interestrequired by the Mississippi PSC's order in the Kemper IGCC. On May 20, 2015, Cooperative Energy notifiedSettlement Docket. Under the RMP, Mississippi Power ofproposes alternatives that would reduce its terminationreserve margin, with the most economic of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note inalternatives being the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership,two-year and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and scheduleseven-year acceleration of the Kemper IGCCretirement of Plant Watson Units 4 and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating5, respectively, to the Kemper IGCC; askfirst quarter 2022 and the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business relatedfour-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the Kemper IGCCthird quarter 2021 and the third quarter 2022, respectively, in Mississippi;order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million,system reliability improvements, as well as unspecified punitive damages. Southern Company,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 and SCS movedwould require authorization to compel arbitration pursuant todefer in a regulatory asset for future recovery the termsremaining net book value of the CO2 contract, whichunits at the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
time of retirement. Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact onexpects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in these matters, and thePSC. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews However, if approved by the Mississippi PSC, and prohibits the cancellation ofalternatives are not expected to have any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.adverse impact on customer rates.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.
Bonus Depreciation
All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Mississippi Power recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.FINANCIAL CONDITION AND LIQUIDITY –
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

"Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
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 regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air qualitylaws and water standards,regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The SEC is conducting a formal investigationsettlement proceeds of Southern Company$18 million, net of expenses and income tax, are included in Mississippi Power's earnings for the nine months ended September 30, 2018.
To mitigate customer rate impacts associated with rising costs and declining sales, Mississippi Power concerningmanagement approved an employee attrition plan on July 13, 2018. In the estimated costs and expected in-service date of the Kemper IGCC. Southern Company andthird quarter 2018, Mississippi Power believerecorded $14 million in expenses related to this plan.
On October 2, 2018, the investigation is focused primarily on periods subsequentMississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated withcontinue providing retail service to the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC.Chevron refinery in Pascagoula, Mississippi through 2038. The ultimate outcome of this matter cannot be determined at this time; however, it isnew agreements are not expected to have a material impact on earnings.
Litigation
In 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Mississippi Power's financial statementsstatements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in this matter, the ultimate outcome of which cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, AFUDC, Unbilled Revenues, and Contingent Obligations.estimates.
Kemper IGCC Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated ConstructionCounty Energy Facility Closure Costs Project Completion Date, and Rate Recovery" of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the September 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017,2018, Mississippi Power has recorded a totalcharges to income of approximately $1.3 billion in costs associated withan immaterial amount for the combined cycle portion ofthird quarter 2018 and $45 million ($34 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 IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includesCounty energy facility. Additional closure costs in excess of the original 2010 estimate for the combined cycle portionmine and gasifier-related assets, currently estimated to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the facility, as well asfirst half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculatedmine and gasifier-related assets, are estimated at $2 million for the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods,remainder of 2018, $8 million in 2019, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions.$4 million annually beginning in 2020. The ultimate outcome willof this matter cannot be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in 2017 and 2016, respectively.at this time.
Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates,See Notes 1 and the impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle""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 "Integrated Coal Gasification Combined CycleKemper 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.
information regarding ASU No. 2016-02, In 2014,Leases (Topic 842) (ASU 2016-02). See Note (A) to the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidanceCondensed Financial Statements herein for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosuresinformation regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Mississippi Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Mississippi Power's revenue, includingrecently adopted accounting standards.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Mississippi Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.
Mississippi Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Mississippi Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Mississippi Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power intends to use the modified retrospective method of adoption effective January 1, 2018. Mississippi Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Mississippi Power's financial statements, Mississippi Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On March 10, 2017,2016, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving2016-02, which requires lessees to recognize on the Presentationbalance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of Net Periodic Pension Costexpense associated with leases and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer reportprovides clarification regarding the service cost component in the same line item or items as other compensation costs and requires the otheridentification of certain components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost componentcontracts that would represent a lease. The accounting required by lessors is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations.relatively unchanged. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Mississippi Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Mississippi Power's financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 2017-122016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Mississippi Power is evaluatingwill adopt the new standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption2019.
Mississippi Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2017-12 is not expected to have2016-02 on a material impact on Mississippi Power's financial statements.prospective basis as of the
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

adoption date of January 1, 2019, without restating prior periods. Mississippi Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Mississippi Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Mississippi Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Mississippi Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Mississippi Power has substantially completed its lease inventory and determined its most significant leases involve equipment and railcar leases. While Mississippi Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is not expected to have a material impact on Mississippi Power's balance sheet or statement of income.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2017 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
Mississippi Power's cash requirements primarily consist of funding ongoing operations, capital expenditures, and debt maturities are expected to materially exceed operating cash flows through 2022. Projected capitalmaturities. Capital expenditures in that periodand other investing activities include investments to maintain existing generation facilities, to addcomply with environmental regulations including adding environmental modifications to certain existing generating units, and to expand and improve transmission and distribution facilities.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 $200 million was repaid in the second quarter 2017, Mississippi Power borrowed an additional $402018 and $100 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power.was repaid in the third quarter 2018. Mississippi Power used a portion of the proceeds from these financings to prepay $901repay a $900 million of outstanding debt.unsecured term loan.
As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs.
Net cash provided from operating activities totaled $361$656 million for the first nine months of 2017, a decrease2018, an increase of $12$295 million as compared to the corresponding period in 2016.2017. The decreaseincrease in net cash provided from operating activities is primarily duerelated to deferredincreased income taxestax refunds in 2018 primarily related to the tax abandonment of the Kemper IGCC, partially offset by an increase in ad valorem taxes and the timing of payments received from affiliates and customers and the completioncollections of Mirror CWIP refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information.receivables. Net cash used for investing activities totaled $483$170 million for the first nine months of 20172018 primarily due to gross property additions related to the Kemper IGCC.steam production, distribution, and transmission. Net cash provided fromused for financing activities totaled $129$355 million for the first nine months of 20172018 primarily due to capital contributions from Southern Company,redemptions of long-term debt and short-term borrowings, partially offset by redemptionsthe issuance of long-term debtsenior notes and short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 20172018 include an increaseincreases of $435 million in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt and $10 million of short-term debt. Securities due within one year decreased $551 million due to the repayment of promissory notes to Southern Company. Long-term debt decreased primarily due to the reclassificationissuance of $1.2 billionsenior notes and $131 million in unsecured term loanscash and cash equivalents primarily due to securities due within one year. Other significant changes include decreasestax refunds, a net change of $2.5 billion in CWIP, $756$440 million in accumulated deferred income taxes and $299 million in deferred charges relatedprimarily due to income taxes. Allthe tax abandonment of these changes primarily resulted from the Kemper IGCC, suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreaseda decrease of $785 million in securities due within one year due to tax refunds associated with the IRS Section 174 R&E settlement. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.repayment of a $900 million unsecured term loan.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations,
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

description of Mississippi Power's capital requirements and contractual obligations. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019. There are no additional scheduled maturities or announced redemptions of long-term debt as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $935 million will be required through September 30, 2018 to fund maturities of long-term debt and $4 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 and2019. Approximately $50 million of fixed rate pollution control revenue bonds that arewill be required to be remarketed over the next 12 months. See "Sources of Capital" and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.
The construction program of Mississippi Power is currently estimatedPower's purchase commitments related to be $582 million for 2017, $203LTSAs have changed to approximately $43 million for 2018, $177$28 million for 2019, $204$28 million for 2020, $199$29 million for 2021, and $240$49 million for 2022. These2022, and $257 million for 2023 and thereafter due to an increase in estimated expenditures do not include potential compliance costs that may arise fromcovered under the EPA's final rules and guidelines or future state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.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 statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows, lines of credit, bank term loans, external security issuances, term loans, and/or short-term debt, as well as, under certain circumstances,commercial paper (to the extent it is eligible to participate), monetization of income tax deductions associated with the abandonment of the gasifier portion of the Kemper County energy facility, and equity contributions and/or loans from Southern Company. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of the Kemper County energy facility cost recovery.factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" of Mississippi Power in Item 7 of the Form 10-K for additional information.
On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
As of September 30, 2017, Mississippi Power's current liabilities exceededsometimes exceed current assets by approximately $769 million primarily due to $935 million inbecause of long-term debt that matures withinmaturities and the next 12 months and $94 millionperiodic use of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans,debt as
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

market conditions permit, a funding source, as well as under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capitalsignificant seasonal fluctuations in cash needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
At September 30, 2017,2018, Mississippi Power had approximately $231$379 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 20172018 were as follows:
ExpiresExpires   
Executable Term
Loans
 
Expires Within One
Year
Expires   
Executable Term
Loans
 
Expires Within One
Year
2017 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
20192019 Total Unused 
One
Year
 
Term
Out
 
No Term
Out
(in millions)
$100
 $100
 $100
 $—
 $—
 $—
 $100
100
 $100
 $100
 $—
 $—
 $—
See Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
MostAll of these bank credit arrangements as well as Mississippi Power's term loan agreement, contain covenants that limit debt levels and typically contain cross acceleration to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017,2018, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 20172018 was approximately $40 million. In addition, at September 30, 2017,2018, Mississippi Power had approximately $50 million of fixed rate pollution controlrevenue bonds outstanding that were required to be remarketed within the next 12 months.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowings were as follows:
  Short-term Debt at September 30, 2017 
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 $4
 3.8% $28
 2.8% $126
  
Short-term Debt During the Period(*)
  
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)
Short-term bank debt $50
 3.3% $100
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.2018. No short-term debt was outstanding at September 30, 2018.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk
At September 30, 2017,2018, Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
On October 4, 2017,2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power executed agreements withand its largest retail customer, Chevron, for Mississippi Power 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 $93 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 September 30, 2017,2018, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $255$202 million.
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Mississippi Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Mississippi Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017,February 26, 2018, Moody's revised its rating outlook for Mississippi Power from under reviewstable to stable.positive. On August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.
Financing Activities
In March 2017,On February 28, 2018, Fitch removed Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In February 2017, Mississippi Power amended $551 million in promissory notesfrom rating watch negative and revised its rating outlook from stable to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.
In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.
In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.positive.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Mississippi Power, may be negatively impacted. The PEP Settlement Agreement is expected to help mitigate these potential adverse impacts by allowing Mississippi Power to retain the excess deferred taxes resulting from the Tax Reform Legislation until the conclusion of the 2019 Base Rate Case. In addition, Mississippi Power has committed to seek equity contributions sufficient to restore its equity ratio to the 50% target. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.
Financing Activities
In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.
In July 2018, Mississippi Power purchased and held approximately $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002. Mississippi Power may reoffer these bonds to the public at a later date.
Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.
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.

Table of Contents

SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

Table of Contents

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Wholesale revenues, non-affiliates$510
 $387
 $1,293
 $866
$496
 $510
 $1,363
 $1,293
Wholesale revenues, affiliates105
 110
 295
 313
134
 105
 326
 295
Other revenues3
 3
 9
 10
5
 3
 10
 9
Total operating revenues618
 500
 1,597
 1,189
635
 618
 1,699
 1,597
Operating Expenses:              
Fuel189
 154
 460
 341
190
 189
 511
 460
Purchased power, non-affiliates36
 25
 90
 60
Purchased power, affiliates7
 8
 23
 16
Purchased power37
 43
 137
 113
Other operations and maintenance83
 81
 272
 246
94
 83
 278
 272
Depreciation and amortization131
 93
 379
 247
130
 131
 370
 379
Taxes other than income taxes13
 5
 37
 17
12
 13
 36
 37
Asset impairment36
 —
 155
 —
Total operating expenses459

366
 1,261
 927
499

459
 1,487
 1,261
Operating Income159
 134
 336
 262
136
 159
 212
 336
Other Income and (Expense):              
Interest expense, net of amounts capitalized(47) (35) (144) (78)(45) (47) (138) (144)
Other income (expense), net3
 2
 3
 3
17
 3
 22
 3
Total other income and (expense)(44) (33) (141) (75)(28) (44) (116) (141)
Earnings Before Income Taxes115
 101
 195
 187
108
 115
 96
 195
Income taxes (benefit)(39) (102) (129) (167)(38) (39) (210) (129)
Net Income154
 203
 324
 354
146
 154
 306
 324
Less: Net income attributable to noncontrolling interests30
 27
 48
 39
Net income attributable to noncontrolling interests54
 30
 71
 48
Net Income Attributable to Southern Power$124
 $176
 $276
 $315
$92
 $124
 $235
 $276
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months Ended September 30, For the Nine Months Ended September 30,For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 20162018 2017 2018 2017
(in millions) (in millions)(in millions) (in millions)
Net Income$154
 $203
 $324
 $354
$146
 $154
 $306
 $324
Other comprehensive income (loss):              
Qualifying hedges:              
Changes in fair value, net of tax of
$15, $14, $35, and $(1), respectively		25
 23
 58
 (1)
Reclassification adjustment for amounts included in net income,
net of tax of $(12), $(1), $(42), and $7, respectively		(20) (1) (68) 13
Changes in fair value, net of tax of
$(4), $15, $(7), and $35, respectively		(11) 25
 (19) 58
Reclassification adjustment for amounts included in net income,
net of tax of $4, $(12), $16, and $(42), respectively		11
 (20) 46
 (68)
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)5
 22
 (10) 12
—
 5
 28
 (10)
Comprehensive Income159
 225
 314
 366
146
 159
 334
 314
Less: Comprehensive income attributable to noncontrolling interests30
 27
 48
 39
Comprehensive income attributable to noncontrolling interests54
 30
 71
 48
Comprehensive Income Attributable to Southern Power$129
 $198
 $266
 $327
$92
 $129
 $263
 $266
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

Table of Contents

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$306
 $324
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total394
 404
Deferred income taxes(337) 240
Amortization of investment tax credits(43) (42)
Income taxes receivable, non-current(12) (42)
Asset impairment155
 —
Other, net10
 (4)
Changes in certain current assets and liabilities —   
-Receivables(41) (77)
-Prepaid income taxes5
 24
-Other current assets1
 14
-Accounts payable(27) (31)
-Accrued taxes256
 79
-Other current liabilities(1) 5
Net cash provided from operating activities666
 894
Investing Activities:   
Business acquisitions(64) (1,016)
Property additions(226) (218)
Change in construction payables3
 (166)
Payments pursuant to LTSAs(57) (99)
Other investing activities20
 7
Net cash used for investing activities(324) (1,492)
Financing Activities:   
Decrease in notes payable, net(68) (89)
Proceeds —   
Short-term borrowings200
 —
Other long-term debt—
 43
Redemptions —   
Senior notes(350) —
Other long-term debt(420) (4)
Return of capital(650) —
Distributions to noncontrolling interests(86) (89)
Capital contributions from noncontrolling interests1,333
 79
Payment of common stock dividends(234) (238)
Other financing activities(15) (27)
Net cash used for financing activities(290) (325)
Net Change in Cash, Cash Equivalents, and Restricted Cash52
 (923)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period140
 1,112
Cash, Cash Equivalents, and Restricted Cash at End of Period$192
 $189
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $14 and $7 capitalized for 2018 and 2017, respectively)$138
 $144
Income taxes, net(102) (343)
Noncash transactions — Accrued property additions at end of period37
 16
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

Table of Contents

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $192
 $129
Receivables —    
Customer accounts receivable 150
 117
Affiliated 71
 50
Other 62
 98
Materials and supplies 214
 278
Prepaid income taxes 44
 50
Assets held for sale, current 18
 1
Other current assets 29
 35
Total current assets 780
 758
Property, Plant, and Equipment:    
In service 13,603
 13,755
Less: Accumulated provision for depreciation 2,087
 1,910
Plant in service, net of depreciation 11,516
 11,845
Construction work in progress 586
 511
Total property, plant, and equipment 12,102
 12,356
Other Property and Investments:    
Intangible assets, net of amortization of $66 and $47
at September 30, 2018 and December 31, 2017, respectively		 391
 411
Total other property and investments 391
 411
Deferred Charges and Other Assets:    
Prepaid LTSAs 106
 118
Accumulated deferred income taxes 1,281
 925
Income taxes receivable, non-current 84
 72
Assets held for sale 185
 —
Other deferred charges and assets 426
 566
Total deferred charges and other assets 2,082
 1,681
Total Assets $15,355
 $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 STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months Ended September 30,
 2017 2016
 (in millions)
Operating Activities:   
Net income$324
 $354
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total404
 262
Deferred income taxes240
 (668)
Amortization of investment tax credits(42) (25)
Collateral deposits(1) (80)
Income taxes receivable, non-current(42) —
Other, net(2) 19
Changes in certain current assets and liabilities —   
-Receivables(77) (82)
-Other current assets38
 (15)
-Accounts payable(31) 7
-Accrued taxes79
 483
-Other current liabilities5
 14
Net cash provided from operating activities895
 269
Investing Activities:   
Business acquisitions(1,032) (1,134)
Property additions(218) (1,702)
Change in construction payables(166) (69)
Payments pursuant to LTSAs(99) (58)
Investment in restricted cash(16) (750)
Distribution of restricted cash33
 746
Other investing activities7
 (41)
Net cash used for investing activities(1,491) (3,008)
Financing Activities:   
Increase (decrease) in notes payable, net(89) 692
Proceeds —   
Senior notes—
 1,531
Capital contributions from parent company—
 800
Other long-term debt43
 63
Redemptions — Other long-term debt(4) (84)
Distributions to noncontrolling interests(89) (22)
Capital contributions from noncontrolling interests79
 367
Purchase of membership interests from noncontrolling interests—
 (129)
Payment of common stock dividends(238) (204)
Other financing activities(27) (14)
Net cash provided from (used for) financing activities(325) 3,000
Net Change in Cash and Cash Equivalents(921) 261
Cash and Cash Equivalents at Beginning of Period1,099
 830
Cash and Cash Equivalents at End of Period$178
 $1,091
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively)$144
 $49
Income taxes, net(343) 71
Noncash transactions — Accrued property additions at end of period16
 210
The accompanying notes as they relate to Southern Power are an integral partTable of these condensed consolidated financial statements.Contents

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30, 2017 At December 31, 2016
  (in millions)
Current Assets:    
Cash and cash equivalents $178
 $1,099
Receivables —    
Customer accounts receivable 148
 102
Other 61
 34
Affiliated 74
 57
Fossil fuel stock 15
 15
Materials and supplies 351
 337
Prepaid income taxes 51
 74
Other current assets 26
 39
Total current assets 904
 1,757
Property, Plant, and Equipment:    
In service 13,734
 12,728
Less: Accumulated provision for depreciation 1,823
 1,484
Plant in service, net of depreciation 11,911
 11,244
Construction work in progress 425
 398
Total property, plant, and equipment 12,336
 11,642
Other Property and Investments:    
Intangible assets, net of amortization of $41 and $22
at September 30, 2017 and December 31, 2016, respectively		 417
 436
Total other property and investments 417
 436
Deferred Charges and Other Assets:    
Prepaid LTSAs 77
 101
Accumulated deferred income taxes 400
 594
Income taxes receivable, non-current 53
 11
Other deferred charges and assets — affiliated 6
 13
Other deferred charges and assets — non-affiliated 455
 615
Total deferred charges and other assets 991
 1,334
Total Assets $14,648
 $15,169
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 September 30, 2017 At December 31, 2016 At September 30, 2018 At December 31, 2017
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $864
 $560
 $—
 $770
Notes payable 120
 209
 237
 105
Accounts payable —        
Affiliated 93
 88
 86
 102
Other 84
 278
 88
 103
Accrued taxes —    
Accrued income taxes 101
 148
 233
 —
Other accrued taxes 30
 7
Accrued interest 36
 36
Acquisitions payable —
 461
Contingent consideration 15
 46
Liabilities held for sale, current 4
 —
Other current liabilities 58
 70
 165
 152
Total current liabilities 1,401
 1,903
 813
 1,232
Long-term Debt 4,946
 5,068
 5,029
 5,071
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 191
 152
 111
 199
Accumulated deferred ITCs 1,900
 1,839
 1,842
 1,884
Asset retirement obligations 76
 64
Other deferred credits and liabilities 232
 304
 259
 322
Total deferred credits and other liabilities 2,399
 2,359
 2,212
 2,405
Total Liabilities 8,746
 9,330
 8,054
 8,708
Redeemable Noncontrolling Interests 59
 164
Common Stockholder's Equity:        
Common stock, par value $.01 per share —    
Common stock, par value $0.01 per share —    
Authorized — 1,000,000 shares        
Outstanding — 1,000 shares —
 —
 —
 —
Paid-in capital 3,661
 3,671
 2,604
 3,662
Retained earnings 762
 724
 1,478
 1,478
Accumulated other comprehensive income 25
 35
Accumulated other comprehensive income (loss) 31
 (2)
Total common stockholder's equity 4,448
 4,430
 4,113
 5,138
Noncontrolling interests 1,395
 1,245
 3,188
 1,360
Total stockholders' equity 5,843
 5,675
 7,301
 6,498
Total Liabilities and Stockholders' Equity $14,648
 $15,169
 $15,355
 $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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


THIRD QUARTER 20172018 vs. THIRD QUARTER 20162017
AND
YEAR-TO-DATE 20172018 vs. YEAR-TO-DATE 20162017


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 and development 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 constructedcommitted to the construction or acquiredacquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion. In addition, Southern Power entered into an agreement to sell all of its equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants), for an aggregate purchase price of $195 million. The sale is expected to occur in the first quarter 2019. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) and FERC and state commission approvals and is expected to close mid-2019. See FUTURE EARNINGS POTENTIAL and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of these matters cannot be determined at this time.
During the nine months ended September 30, 2017,2018, Southern Power acquired or completed the construction of, and placed in service approximately 498 MWs ofthe 20-MW Gaskell West 1 solar and wind facilities. In addition, Southern Power began construction atfacility, placed in service the recently acquired148-MW Cactus Flats wind facility, continued developmentacquired and began construction of its portfolio ofthe 100-MW Wild Horse Mountain and the 200-MW Reading wind projects,facilities, and continued construction of the expansion of the 385-MW Mankato natural gas facility by 345 MWs of capacity.facility. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
At September 30, 2017,2018, Southern Power had anPower's average investment coverage ratio for its generating assets (including the Florida and Mankato 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 discussed herein) as the investment amount, was 93% through 2022 and 91% through 2021 and 90% through 2026,2027, with an average remaining contract duration of approximately 1615 years. These ratios include the PPAs and capacity associated with facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.
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.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(52) (29.5) $(39) (12.4)
Net income attributable to Southern Power for the third quarter 2017 was $124 million compared to $176 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits from solar ITCs and increased interest expense primarily due to a decrease in capitalized interest associated with completing construction of and placing in service solar facilities, partially offset by additional operating income related to new generating facilities.
Net income attributable to Southern Power for year-to-date 2017 was $276 million compared to $315 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits resulting from a reduction in solar ITCs, partially offset by an increase in wind PTCs, and increased interest expense from debt issuances to fund Southern Power's growth strategy and continuous construction program, partially offset by additional operating income from new generating facilities.
For additional information on new generating facilities placed in service during 2016 and 2017, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


"Construction Projects"RESULTS OF OPERATIONS
Net Income Attributable to Southern Power
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(32) (25.8) $(41) (14.9)
Net income attributable to Southern Power for the third quarter 2018 was $92 million compared to $124 million for the corresponding period in 2017. The decrease was primarily due to a $36 million asset impairment charge ($27 million after tax) on wind turbine equipment held for development projects and $23 million from a reduction in income tax benefits primarily from ITCs related to solar facilities placed in service, partially offset by $11 million in state income tax benefits arising from the reorganization of legal entities that own and operate certain of Southern Power's wind facilities.
Net income attributable to Southern Power for year-to-date 2018 was $235 million compared to $276 million for the corresponding period in Item 72017. The decrease was primarily due to a $119 million asset impairment charge as a result of the Form 10-Kpending sale of the Florida Plants in the second quarter 2018 and FUTURE EARNINGS POTENTIAL – "Acquisitions"a $36 million asset impairment charge on wind turbine equipment held for development projects (together $116 million after tax) and "Construction Projects" herein.$25 million from a reduction in income tax benefits primarily from ITCs related to solar facilities placed in service, partially offset by approximately $65 million in state income tax benefits arising from reorganizations of legal entities that own and operate certain of Southern Power's solar and wind facilities.
Operating Revenues
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$118 23.6 $408 34.3
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$17 2.8 $102 6.4
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 which include sales from Southern Power's natural gas, biomass, solar, and windgeneration facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into the wholesale market and, to the extent the generation assets are part of the IIC, as approved by the FERC, it may sell power into the power pool.
Natural Gas and Biomass Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have a capacity charge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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:
Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2018 Third Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
(in millions)(in millions)
PPA capacity revenues$169
 $149
 $466
 $406
$168
 $169
 $450
 $466
PPA energy revenues299
 247
 765
 532
336
 299
 892
 765
Total PPA revenues468
 396
 1,231
 938
504
 468
 1,342
 1,231
Non-PPA revenues147
 101
 357
 241
126
 147
 347
 357
Other revenues3
 3
 9
 10
5
 3
 10
 9
Total operating revenues$618
 $500
 $1,597
 $1,189
$635
 $618
 $1,699
 $1,597
In the third quarter 2018, total operating revenues were $635 million, reflecting a $17 million, or 3%, increase from the corresponding period in 2017. The increase in operating revenues was primarily due to the following:
PPA energy revenues increased $37 million, or 12%, primarily due to increases of $20 million from new natural gas PPAs from existing facilities, $9 million from renewable facilities primarily due to an increase in the volume of KWHs sold, and $8 million in fuel costs that are contractually recovered through existing PPAs.
Non-PPA revenues decreased $21 million, or 14%, primarily due to the volume of KWHs sold from uncovered natural gas capacity through short-term sales.
For year-to-date 2018, total operating revenues were $1.7 billion, reflecting an $102 million, or 6%, increase from the corresponding period in 2017. The increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $16 million, or 3%, primarily due to the contractual expiration of an affiliate natural gas PPA.
PPA energy revenues increased $127 million, or 17%, primarily due to increases of $56 million from new natural gas PPAs from existing facilities, $45 million in fuel costs that are contractually recovered through existing PPAs, and $27 million from renewable facilities primarily due to an increase in the volume of KWHs sold.
Non-PPA revenues decreased $10 million, or 3%, primarily due to the volume of KWHs sold from uncovered natural gas capacity through short-term sales.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


In the third quarter 2017, total operating revenues were $618 million, reflecting a $118 million, or 24%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $20 million, or 13%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $52 million, or 21%, primarily due to a $55 million increase in sales from new solar and wind facilities, partially offset by a $3 million decrease in sales from natural gas PPAs due to a $24 million decrease in volume primarily due to the expiration of a PPA and reduced customer load, partially offset by a $21 million increase in the average cost of fuel.
Non-PPA revenues increased $46 million, or 46%, due to a $58 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, offset by a $12 million decrease in the price of energy in the wholesale markets.
For year-to-date 2017, total operating revenues were $1.6 billion, reflecting a $408 million, or 34%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $60 million, or 15%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $233 million, or 44%, primarily due to a $188 million increase in sales from new solar and wind facilities and a $35 million increase in sales from natural gas PPAs primarily due to a $69 million increase in the average cost of fuel, partially offset by a $34 million decrease in volume primarily due to the expiration of a PPA and reduced customer load.
Non-PPA revenues increased $116 million, or 48%, due to a $104 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $12 million increase in the price of energy in the wholesale markets.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market.market including the power pool. Details of Southern Power's generation and purchased power were as follows:
Third Quarter 2017Third Quarter 2016 Year-to-Date 2017Year-to-Date 2016Third Quarter 2018Third Quarter 2017 Year-to-Date 2018Year-to-Date 2017
(in billions of KWHs)(in billions of KWHs)
Generation12.511.1 33.227.913.312.5 35.333.2
Purchased power1.20.9 3.42.50.91.2 3.13.4
Total generation and purchased power13.712.0 36.630.414.213.7 38.436.6
  
Total generation and purchased power, excluding solar, wind, and tolling agreements7.26.7 17.817.78.27.2 22.217.8
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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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:
Third Quarter 2017
vs.
Third Quarter 2016		 Year-to-Date 2017
vs.
Year-to-Date 2016		Third Quarter 2018 vs. Third Quarter 2017 
Year-to-Date 2018 vs.
Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$35
 22.7 $119
 34.9$1
 0.5 $51
 11.1
Purchased power10
 30.3 37
 48.7(6) (14.0) 24
 21.2
Total fuel and purchased power expenses$45
 $156
 $(5) $75
 
In the third quarter 2017,2018, total fuel and purchased power expenses increased $45decreased $5 million, or 24.1%2%, compared to the corresponding period in 2016.2017. Fuel expense increased $35$1 million primarily due to a $29 million increase in the average cost of natural gas per KWH generated and an $8$43 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $10agreements, partially offset by a $42 million primarily due to an increase in the volume of KWHs purchased.
For year-to-date 2017, total fuel and purchased power expenses increased $156 million, or 37.4%, compared to the corresponding period in 2016. Fuel expense increased $119 million primarily due to a $139 million increasedecrease in the average cost of natural gas per KWH generated,generated. Purchased power expense decreased $6 million due to a $9 million decrease in the volume of KWHs purchased, partially offset by a $19$3 million decreaseincrease in the average cost of purchased power.
For year-to-date 2018, total fuel and purchased power expenses increased $75 million, or 13%, compared to the corresponding period in 2017. Fuel expense increased $51 million primarily due to a $152 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements.agreements, partially offset by a $101 million decrease in the average cost of natural gas per KWH generated. Purchased power expense increased $37$24 million primarily due to a $28$33 million increase in the average cost of purchased power primarily in first quarter 2018, partially offset by a $9 million decrease in the volume of KWHs purchased and a $9 million increase associated with the average cost of purchased power.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$2 2.5 $26 10.6
In the third quarter 2017, other operations and maintenance expenses were $83 million compared to $81 million for the corresponding period in 2016. The increase was primarily due to a $13 million increase associated with new solar, wind, and gas facilities, partially offset by a $5 million decrease in scheduled outage maintenance expenses and a $5 million decrease in non-outage operations and maintenance expenses.
For year-to-date 2017, other operations and maintenance expenses were $272 million compared to $246 million for the corresponding period in 2016. The increase was primarily due to a $48 million increase associated with new solar, wind, and gas facilities and an $8 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $22 million decrease in scheduled outage maintenance expenses and an $8 million decrease in non-outage operations and maintenance expenses.purchased.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Depreciation and AmortizationAsset Impairment
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$38 40.9 $132 53.4
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$36 N/M $155 N/M
N/M - Not meaningful
In the thirdsecond quarter 2017, depreciation and amortization2018, a $119 million asset impairment charge was $131 million compared to $93 million forrecorded in contemplation of the corresponding periodsale of the Florida Plants. In addition, in 2016. For year-to-date 2017, depreciation and amortization was $379 million compared to $247 million for the corresponding period in 2016. The increases were primarily due to new solar, wind, and gas facilities placed in service.
Taxes Other Than Income Taxes
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$8 160.0 $20 117.6
In the third quarter 2017, taxes other than income taxes were $132018, a $36 million comparedasset impairment charge was recorded on wind turbine equipment held for development projects. See Note (J) under "Southern Power – Sale of Florida Plants" and " – Development Projects" to $5 millionthe Condensed Financial Statements herein for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $37 million compared to $17 million for the corresponding period in 2016. These increases were primarily due to additional property taxes due to new solar, wind, and gas facilities.
Interest Expense, net of Amounts Capitalized
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$12 34.3 $66 84.6
In the third quarter 2017, interest expense, net of amounts capitalized was $47 million compared to $35 million for the corresponding period in 2016. The increase was primarily due to an $8 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities and an increase of $3 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program.
For year-to-date 2017, interest expense, net of amounts capitalized was $144 million compared to $78 million for the corresponding period in 2016. The increase was primarily due to an increase of $39 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $25 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
information.
Other Income (Expense), Net
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$1 50.0 $— —
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$14 N/M $19 N/M
N/M - Not meaningful
In the third quarter 2017,2018, other income (expense), net was $3$17 million compared to $2$3 million for the corresponding period in 2016. Other2017. For year-to-date 2018, other income (expense), net was $22 million compared to $3 million for both year-to-date 2017the corresponding period in 2017. These increases were primarily due to a $14 million gain from a joint-development wind project, which is attributable to Southern Power's partner in the project and 2016. The changes include increases of $36 million and $152 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars forfully offset within noncontrolling interests.
Income Taxes (Benefit)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$1 2.6 $(81) (62.8)
In the third quarter 2018, income tax benefit was $38 million compared to $39 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $210 million compared to $129 million for the corresponding period in 2017. These changes were primarily due to lower pre-tax earnings, primarily resulting from asset impairment charges, and year-to-date 2017, respectively, fullyincome tax benefits related to certain changes in state apportionment rates arising from reorganizations of Southern Power's legal entities that own and operate certain of its solar and wind facilities, partially offset by an equal changea decrease in gains onincome tax benefits from solar ITCs, primarily as a result of a decrease in the foreign currency hedges that were reclassified from accumulated OCI into earnings.number of facilities placed in service in 2018 as compared to 2017. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Legal Entity Reorganizations" and Note (H) to the Condensed Financial Statements herein for additional information.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Net Income Taxes (Benefit)Attributable to Noncontrolling Interests
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$63 61.8 $38 22.8
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$24 80.0 $23 47.9
In the third quarter 2017,2018, net income tax benefitattributable to noncontrolling interests was $39$54 million compared to $102$30 million for the corresponding period in 2016.2017. The decreaseincrease was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to the sale of a $61 million decrease33% equity interest in income tax benefits from solar ITCs.SPSH in 2018.
For year-to-date 2017,2018, net income tax benefitattributable to noncontrolling interests was $129$71 million compared to $167$48 million for the corresponding period in 2016.2017. The decreaseincrease was primarily due to $21 million of net income allocations due to the sale of a $10233% equity interest in SPSH in 2018 and $14 million decrease inof other income tax benefits from solar ITCs,allocations attributable to a joint-development wind project, partially offset by a $58reduction of $10 million increase in wind PTCs and a $4 million increase resulting from state apportionment rate changes.of net income allocations primarily due to the tax equity partnership for Gaskell West 1.
See Note (G)(J) to the Condensed Financial Statements under "Southern Power" herein for additional information on income taxes and Note 1 to the financial statements of Southern Power under "Income and Other Taxes" in Item 8 of the Form 10-K for additional information on ITCs and PTCs.information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to develop and construct generating facilities. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules, and cannot be determined at this time, but could have a material impact on Southern Power's consolidated financial statements.strategy.
In May 2018, Southern Power is consideringcompleted the sale of up to a one-third33% equity interest in SPSH, a 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. Accordingly, Global Atlantic will receive 33% of all cash distributions paid by SPSH. Southern Power continues to consolidate the assets and liabilities of SPSH with Global Atlantic's share of partnership earnings reflected in net income attributable to noncontrolling interests in the Condensed Consolidated Statements of Income.
Also in May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its solar asset portfolio.equity interests in the Florida Plants for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The sale is expected to occur in the first quarter 2019. Pre-tax net income for the Florida Plants was $18 million and $11 million for the three months ended September 30, 2018 and 2017, respectively, and $40 million and $28 million for the nine months ended September 30, 2018 and 2017, respectively. The ultimate outcome of this matter cannot be determined at this time.
On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in Class A tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Upon closing, the tax equity partners will have a claim to certain cash distributions and an allocation of tax attributes. See "Income Tax Matters – Legal Entity Reorganizations" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
On November 5, 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 $650 million, subject to customary working capital and timing adjustments. The ultimate purchase
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


price will decrease $66,667 per day for each day after June 1, 2019, if the expansion has not achieved commercial operation, but such decrease will not exceed $15 million. This transaction is subject to the expiration or termination of the waiting period under the HSR Act and FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.
Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings.
Other factors that could influence future earnings include weather, demand,transmission constraints, cost of generation from facilitiesunits 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 September 30, 2017,2018, Southern Power's average investment coverage ratio for its generating assets (including the Florida and Mankato 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)construction and acquisitions discussed herein) as the investment amount, was 93% through 2022 and 91% through 2021 and 90% through 2026,2027, with an average remaining contract duration of approximately 1615 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
The ultimate outcome of this matter cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacementguidelines (ELG) rule.
On June 1, 2017,May 2, 2018, the U.S. President announced thatEPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the United StatesELG rule will withdraw fromdepend on the non-binding Paris Agreementcontent of the final rule and begin renegotiation of its terms.
The ultimatethe outcome of these mattersany 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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceedingproceedings related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30,2014 and 2017 triennial updated market power analysis. Theanalyses.
On May 4, 2018, the FERC directedissued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power to show cause within 60 days whysatisfy the FERC's standards for market-based rate authority should not be revoked in certain areas adjacent torates. On May 9, 2018, the area presently under mitigation in accordance withtraditional electric operating companies and Southern Power made the February 2, 2017compliance filing required by the order. These proceedings are concluded.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.
The ultimate outcome of these matters cannot be determined at this time.
Acquisitions
During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy,2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the project discussed below.Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material. See Note (I)(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
BethelWind276Castro County, TX100% January 2017Google Energy, LLC12 years
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 aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The BethelGaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.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 Completed and in Progress and/or Completed
During the nine months ended September 30, 2017, in accordance with its overall growth strategy,2018, Southern Power completed construction of and placed in service,started, continued, or continuedcompleted construction of the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP.table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360$575 million and $415$640 million for the Mankato, Wild Horse Mountain, and Cactus FlatsReading facilities. At September 30, 2018, construction costs included in CWIP related to these projects totaled $246 million. The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Project FacilityResource
Approximate Nameplate Capacity (MW)
Location
Actual/Expected
COD
PPA CounterpartiesPPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East PecosSolar120Pecos County, TXMarch 2017Austin Energy15 years
LamesaSolar102Dawson County, TXApril 2017City of Garland, Texas15 years
Projects Under Construction as of September 30, 2017
Cactus Flats(*)(a)
Wind148Concho County, TXThird quarterJuly 2018General Motors, LLC
and
General Mills Operations, LLC		12 years
and
15 years
MankatoNatural Gas345385Mankato, MNSecond quarterFirst half 2019Northern States Power Company20 years
Wild Horse Mountain(b)
Wind100Pushmataha County, OKFourth quarter 2019Arkansas Electric Cooperative20 years
Reading(c)
Wind200Osage and Lyon Counties, KSSecond quarter 2020Royal Caribbean Cruises LTD12 years
(*)(a)OnIn July 31, 2017, Southern Power acquired apurchased 100% ownership interest inof the Cactus Flats facility which isand commenced construction. In July 2018, the facility was placed in service and, in August 2018, Southern Power closed on a tax equity partnership agreement and owns 100% of the early stages of construction, from RES America Developments, Inc.class B membership interests.
(b)In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.
(c)In August 2018, Southern Power purchased 100% of the membership interests from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Development Projects
In December 2016,During 2017, as part of Southern Power'sits renewable development strategy, oneSouthern 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 using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.
During 2016, Southern Power's wholly-owned subsidiariesPower entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. AlsoIn addition, in December 2016, Southern Power signed agreements and made payments to purchasepurchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. AllAny wind projects using this equipment and reaching commercial operation by the end of 2020 are expected to qualify for 100% PTCs.
In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of the wind turbine equipment was delivered by April 2017, which allowsto potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the third quarter 2018, as a result of a review of various options for probable dispositions of wind turbine equipment not already deployed to development or construction projects, to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. Southern Power recorded a $36 million asset impairment charge on the equipment.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (G)(H) to the Condensed Financial Statements herein for additional information.information regarding the Tax Reform Legislation.
During the third quarter 2017,Legal Entity Reorganizations
In April 2018, Southern Power begancompleted the final stage of 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. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to resultresulted in estimatednet state tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates andtotaling approximately $54 million, which were recorded in the first half of 2018.
In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulationlaws and regulations governing air, water, land, and protection of air emissions and water discharges.natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air qualitylaws and water standards,regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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.
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of Long-Lived Assets and Intangibles, Acquisition Accounting, and ITCs.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.
information regarding ASU No. 2016-02, In 2014,Leases (Topic 842) (ASU 2016-02). See Note (A) to the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidanceCondensed Financial Statements herein for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosuresinformation regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. However, given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income. Southern Power's ongoing evaluation of revenue streams andrecently adopted accounting standards.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


related contracts includes the evaluation of identified revenue streams tied to longer-term contractual arrangements, such as certain capacity and energy payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC 840).
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Power intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Power's financial statements, Southern Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On August 28, 2017,2016, the FASB issued ASU No. 2017-12, Derivatives2016-02, which requires lessees to recognize on the balance sheet a lease liability and Hedging (Topic 815): Targeted Improvements to Accountinga right-of-use asset for Hedging Activities (ASU 2017-12), amendingall leases. ASU 2016-02 also changes the hedge accounting recognition, measurement, and presentation requirements.of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 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 2017-122016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlySouthern Power will adopt the new standard effective January 1, 2019.
Southern Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption permitted. date of January 1, 2019, without restating prior periods. Southern Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption. Southern Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lessee lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes, while lessor lease and non-lease components will be accounted for separately.
Southern Power is evaluatingcontinuing to complete the standardimplementation of an information technology system to track and expectsaccount for its leases and of changes to early adoptits internal controls and accounting policies to support the accounting for leases under ASU 2017-12 effective January 1, 2018. The2016-02. Southern Power has substantially completed its lease inventory and determined its most significant leases as a lessee involve real estate. While Southern Power has not yet determined the ultimate impact, adoption of ASU 2017-122016-02 is not expected to have aresult in recording lease liabilities and right-of-use assets on Southern Power's balance sheet each totaling approximately $0.5 billion, with no material impact on Southern Power's financial statements.statement of income.
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 September 30, 2017.2018. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Southern Power anticipates utilizingalso utilizes third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy; however,strategy where the usetax partner takes significantly all of third-partythe federal tax benefits. These tax equity structures is not expectedpartnerships are consolidated in Southern Power's financial statements using a hypothetical liquidation at book value (HLBV) methodology to have a material impact on future earnings. Subsequentallocate partnership gains and losses to September 30, 2017,Southern Power. During the first nine months of 2018, Southern Power securedobtained third-party tax equity funding for the recently acquiredGaskell West 1 solar project and the Cactus Flats wind project of approximately $26 million and $122 million, respectively. See Note (A) to the Condensed Financial Statements under "Hypothetical Liquidation at Book Value" herein for additional information on the HLBV methodology.
In May 2018, Southern Power received approximately $1.2 billion from the sale of a 33% equity interest in SPSH, a 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.
On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to achieving commercial operationPublic Utility Commission of Texas approval and various other customary conditionsis expected to closing.close by the end of 2018. Southern Power intends to use the proceeds to return capital of approximately $1.0 billion to Southern Company. The ultimate outcome of this matter cannot be determined at this time.
Net cash provided from operating activities totaled $895$666 million for the first nine months of 20172018 compared to $269$894 million for the first nine months of 2016.2017. The increasedecrease in net cash provided from operating activities was primarily due to lower income tax refunds received and an increase in energy salesprimarily due to taxable gains arising from new solar and wind facilities, partially offset by an increasethe sale of a 33% equity interest in interest paid.SPSH. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $1.5 billion$324 million for the first nine months of 20172018 primarily due to payments for renewable acquisitions and the construction of generating facilities.facilities and payments for renewable acquisitions. Net cash used for financing activities totaled $325$290 million for the first nine months of 20172018 primarily due to debt repayments, returns of capital and payments of common stock dividend payments, a decrease in notes payable,dividends to Southern Company, and distributions to noncontrolling interests, partially offset by capital contributionsproceeds from noncontrolling interests.the sale of a 33% equity interest in SPSH. 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 nine months of 20172018 include a $1.0$1.8 billion increase in property, plant,
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


and equipment in-servicenoncontrolling interests primarily due to the sale of SPSH, a $1.1 billion reduction in paid in capital, which includes $410 million related to acquisitionsthe sale of SPSH and completing construction$250 million and $400 million of capital returned to Southern Company in the second and placing in service solar facilities,third quarters 2018, respectively, a $921$770 million decrease in cash and cash equivalents,securities due within one year due to repayments of debt in the second quarter 2018, and a $461$356 million decreaseincrease in acquisitions payable.accumulated deferred income tax assets primarily due to the sale of SPSH.
See FUTURE EARNINGS POTENTIAL – "Acquisitions," "Construction Projects," and "Construction ProjectsIncome Tax Matters – Legal Entity Reorganizations" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program,and contractual obligations. There are no scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase commitments. Approximately $864 million will be required to repay maturities of long-term debt through September 30, 2018.2019.
Southern Power's construction program includes estimates for potential plant acquisitions and placeholder growth, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. PlannedSubsequent to the Tax Reform Legislation, planned expenditures for plant acquisitions 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


under LTSAs remain unchanged and total approximately $0.9 billion for the five years ending 2022. Actual capitalconstruction costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial StatementsFUTURE 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, short-term debt,external securities issuances, term loans,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.
As of September 30, 2017, Southern Power's current liabilities exceededsometimes exceed current assets by $497 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source and construction payables, as well as fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects.seasonality. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, the debt capital markets, and operating cash flows.
As of September 30, 2017,2018, Southern Power had cash and cash equivalents of approximately $178$192 million.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities, for general corporate purposes, and to finance maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheet at September 30, 2017.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


sheets.
Details of commercial papershort-term borrowings were as follows:
 Short-term Debt at September 30, 2017 
Short-term Debt During the Period (*)
 Amount OutstandingWeighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate 
Maximum
Amount
Outstanding
 (in millions)  (in millions)   (in millions)
Commercial paper$120
1.5% $322
 1.5% $416
 Short-term Debt at September 30, 2018 
Short-term Debt During the Period (*)
 Amount OutstandingWeighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate 
Maximum
Amount
Outstanding
 (in millions)  (in millions)   (in millions)
Commercial paper$37
2.5% $44
 2.3% $185
Short-term loans200
2.8% 200
 2.7% 200
Total$237
2.8% $244
 2.6%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.2018.
At September 30, 2017,2018, Southern Power had a committed credit facility (Facility) of $750 million, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, Southern Power amended theThe Facility which, among other things, extended the maturity date from 2020 to 2022 and increased Southern Power's borrowing ability under this Facility to $750 million from $600 million.expires in 2022. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility, as well as Southern Power's term loan agreement,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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Southern Power also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit expiring in 2019.credit. At September 30, 2017, $1112018, $98 million has been used for letters of credit, primarily as credit support for PPA requirements, and $9$22 million remains unused.
In addition, at September 30, 2018, Southern Power had $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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The maximum potential collateral requirements under these contracts at September 30, 20172018 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements		Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and/or Baa2$37
$37
At BBB- and/or Baa3$398
$378
At BB+ and/or Ba1(*)
$1,124
$932
(*)Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Southern Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revisedSeptember 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its consolidatedsubsidiaries (including Southern Power).
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 outlook foragencies to assess Southern Company and its subsidiaries, (includingincluding Southern Power) from stablePower, may be negatively impacted. Absent actions by Southern Power to negative.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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Financing Activities
In September 2017,May 2018, Southern Power amended its $60entered 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 repaid $420 million aggregate principal amount of long-term floating rate bank loan to, among other things, increase theloans and $350 million aggregate principal amount to $100 million and extend the maturity date from September 2017 to Octoberof Series 2015A 1.50% Senior Notes due June 1, 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
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.

Table of Contents

SOUTHERN COMPANY GAS
AND SUBSIDIARY COMPANIES

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
Successor  Predecessor
For the Three Months Ended September 30, For the Three Months Ended September 30, For the Nine Months Ended September 30, July 1, 2016 through September 30,  January 1, 2016 through
June 30,		For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
2017 2016 2017 2016  20162018 2017 2018 2017
(in millions)  (in millions)(in millions) (in millions)
Operating Revenues:                 
Natural gas revenues (includes revenue
taxes of $9, $9, $75, $9, and $57 for the
periods presented, respectively)		$532
 $518
 $2,746
 $518
  $1,841
Natural gas revenues (includes revenue taxes of
$9, $9, $83, and $75, respectively)		$487
 $532
 $2,829
 $2,737
Alternative revenue programs5
 —
 (23) 9
Other revenues33
 25
 95
 25
  64
—
 33
 55
 95
Total operating revenues565
 543
 2,841
 543
  1,905
492
 565
 2,861
 2,841
Operating Expenses:                 
Cost of natural gas134
 133
 1,085
 133
  755
104
 134
 1,053
 1,085
Cost of other sales7
 2
 20
 2
  14
—
 7
 12
 20
Other operations and maintenance205
 216
 671
 216
  454
216
 206
 730
 675
Depreciation and amortization125
 116
 370
 116
  206
119
 125
 374
 370
Taxes other than income taxes26
 29
 140
 29
  99
32
 26
 157
 140
Merger-related expenses—
 35
 —
 35
  56
Gain on dispositions, net(353) —
 (317) —
Goodwill impairment—
 —
 42
 —
Total operating expenses497
 531
 2,286
 531
  1,584
118
 498
 2,051
 2,290
Operating Income68
 12
 555
 12
  321
374
 67
 810
 551
Other Income and (Expense):                 
Earnings from equity method investments32
 29
 100
 29
  2
34
 32
 108
 100
Interest expense, net of amounts capitalized(51) (39) (145) (39)  (96)(52) (51) (170) (145)
Other income (expense), net18
 9
 26
 9
  5
6
 19
 21
 30
Total other income and (expense)(1) (1) (19) (1)  (89)(12) —
 (41) (15)
Earnings Before Income Taxes67
 11
 536
 11
  232
362
 67
 769
 536
Income taxes52
 7
 233
 7
  87
316
 52
 475
 233
Net Income15
 4
 303
 4
  145
$46
 $15
 $294
 $303
Less: Net income attributable to
noncontrolling interest		—
 —
 —
 —
  14
Net Income Attributable to
Southern Company Gas		$15
 $4
 $303
 $4
  $131
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income$46
 $15
 $294
 $303
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of
$-, $-, $1, and $(2), respectively		—
 —
 2
 (3)
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 $2, $-, $2, and $(1), respectively		6
 —
 5
 —
Total other comprehensive income (loss)6
 —
 9
 (3)
Comprehensive Income$52
 $15
 $303
 $300
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$294
 $303
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total374
 370
Deferred income taxes(83) 265
Mark-to-market adjustments23
 (32)
Gain on dispositions, net(317) —
Goodwill impairment42
 —
Other, net(41) (46)
Changes in certain current assets and liabilities —   
-Receivables445
 531
-Natural gas for sale87
 —
-Prepaid income taxes(23) (7)
-Other current assets21
 (42)
-Accounts payable(59) (169)
-Accrued taxes(64) (24)
-Accrued compensation2
 (11)
-Other current liabilities35
 8
Net cash provided from operating activities736
 1,146
Investing Activities:   
Property additions(1,029) (1,093)
Cost of removal, net of salvage(67) (45)
Change in construction payables, net(14) 49
Investment in unconsolidated subsidiaries(90) (128)
Dispositions2,631
 —
Other investing activities18
 28
Net cash provided from (used for) investing activities1,449
 (1,189)
Financing Activities:   
Decrease in notes payable, net(1,382) (323)
Proceeds —   
First mortgage bonds100
 200
Capital contributions from parent company35
 79
Senior notes—
 450
Redemptions — Gas facility revenue bonds(200) —
Return of capital(400) —
Payment of common stock dividends(351) (332)
Other financing activities(3) (29)
Net cash provided from (used for) financing activities(2,201) 45
Net Change in Cash, Cash Equivalents, and Restricted Cash(16) 2
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period78
 24
Cash, Cash Equivalents, and Restricted Cash at End of Period$62
 $26
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $5 and $9 capitalized for 2018 and 2017, respectively)$175
 $146
Income taxes, net682
 17
Noncash transactions — Accrued property additions at end of period121
 112
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $56
 $73
Receivables —    
Energy marketing receivables 498
 607
Customer accounts receivable 180
 400
Unbilled revenues 58
 285
Affiliated 23
 12
Other accounts and notes receivable 110
 91
Accumulated provision for uncollectible accounts (18) (28)
Natural gas for sale 486
 595
Prepaid expenses 62
 53
Assets from risk management activities, net of collateral 87
 135
Other regulatory assets, current 72
 94
Other current assets 88
 78
Total current assets 1,702
 2,395
Property, Plant, and Equipment:    
In service 14,771
 15,833
Less: Accumulated depreciation 4,351
 4,596
Plant in service, net of depreciation 10,420
 11,237
Construction work in progress 660
 491
Total property, plant, and equipment 11,080
 11,728
Other Property and Investments:    
Goodwill 5,015
 5,967
Equity investments in unconsolidated subsidiaries 1,529
 1,477
Other intangible assets, net of amortization of $133 and $120
at September 30, 2018 and December 31, 2017, respectively		 113
 280
Miscellaneous property and investments 20
 21
Total other property and investments 6,677
 7,745
Deferred Charges and Other Assets:    
Other regulatory assets, deferred 721
 901
Other deferred charges and assets 218
 218
Total deferred charges and other assets 939
 1,119
Total Assets $20,398
 $22,987
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 Successor  Predecessor
 For the Three Months Ended September 30, For the Three Months Ended September 30, For the Nine Months Ended September 30, July 1, 2016 through September 30,  January 1, 2016 through
June 30,
 2017 2016 2017 2016  2016
 (in millions)  (in millions)
Net Income$15
 $4
 $303
 $4
  $145
Other comprehensive income (loss):          
Qualifying hedges:          
Changes in fair value, net of tax of
$-, $(2), $(2), $(2), and $(23),
respectively		—
 (3) (3) (3)  (41)
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $-, $-, and $-,
respectively		—
 —
 —
 —
  1
Pension and other postretirement
benefit plans:		          
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $(1), $-, and $4,
respectively		—
 —
 —
 —
  5
Total other comprehensive income (loss)—
 (3) (3) (3)  (35)
Comprehensive Income15
 1
 300
 1
  110
Less: Comprehensive income attributable to
noncontrolling interest		—
 —
 —
 —
  14
Comprehensive Income Attributable to
Southern Company Gas		$15
 $1
 $300
 $1
  $96
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 Successor  Predecessor
 For the Nine Months Ended September 30, July 1, 2016 through September 30,  January 1, 2016 through
June 30,
 2017 2016  2016
 (in millions)  (in millions)
Operating Activities:      
Net income$303
 $4
  $145
Adjustments to reconcile net income
to net cash provided from operating activities —		      
Depreciation and amortization, total370
 116
  206
Deferred income taxes265
 (30)  8
Pension, postretirement, and other employee benefits(4) (123)  5
Stock based compensation expense25
 11
  20
Hedge settlements—
 (35)  (26)
Mark-to-market adjustments(32) 17
  162
Other, net(67) (47)  (82)
Changes in certain current assets and liabilities —      
-Receivables534
 (18)  181
-Natural gas for sale, net of temporary LIFO liquidation—
 (222)  273
-Prepaid income taxes(7) 1
  151
-Other current assets(42) (36)  37
-Accounts payable(169) 78
  43
-Accrued taxes(24) (11)  41
-Accrued compensation(11) (36)  (21)
-Other current liabilities8
 (11)  (30)
Net cash provided from (used for) operating activities1,149
 (342)  1,113
Investing Activities:      
Property additions(1,093) (287)  (509)
Cost of removal, net of salvage(45) (21)  (32)
Change in construction payables, net49
 9
  (7)
Investment in unconsolidated subsidiaries(128) (1,421)  (14)
Returned investment in unconsolidated subsidiaries22
 2
  3
Other investing activities3
 3
  —
Net cash used for investing activities(1,192) (1,715)  (559)
Financing Activities:      
Increase (decrease) in notes payable, net(323) 472
  (896)
Proceeds —      
First mortgage bonds200
 —
  250
Capital contributions from parent company79
 1,089
  —
Senior notes450
 900
  350
Redemptions and repurchases —      
Medium-term notes(22) —
  —
First mortgage bonds—
 —
  (125)
Senior notes—
 (300)  —
Distributions to noncontrolling interest—
 —
  (19)
Payment of common stock dividends(332) (63)  (128)
Other financing activities(7) (8)  10
Net cash provided from (used for) financing activities45
 2,090
  (558)
Net Change in Cash and Cash Equivalents2
 33
  (4)
Cash and Cash Equivalents at Beginning of Period19
 15
  19
Cash and Cash Equivalents at End of Period$21
 $48
  $15
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —      
Interest (net of $9, $2, and $3 capitalized, respectively)$146
 $86
  $119
Income taxes, net17
 54
  (100)
Noncash transactions —
Accrued property additions at end of period		112
 50
  41
The accompanying notes as they relate to Southern Company Gas are an integral partTable of these condensed consolidated financial statements.Contents

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At September 30, 2017 At December 31, 2016
  (in millions)
Current Assets:    
Cash and cash equivalents $21
 $19
Receivables —    
Energy marketing receivables 427
 623
Customer accounts receivable 221
 364
Unbilled revenues 61
 239
Other accounts and notes receivable 61
 76
Accumulated provision for uncollectible accounts (26) (27)
Materials and supplies 24
 26
Natural gas for sale 631
 631
Prepaid expenses 103
 80
Assets from risk management activities, net of collateral 103
 128
Other regulatory assets, current 96
 81
Other current assets 25
 10
Total current assets 1,747
 2,250
Property, Plant, and Equipment:    
In service 15,383
 14,508
Less: Accumulated depreciation 4,567
 4,439
Plant in service, net of depreciation 10,816
 10,069
Construction work in progress 596
 496
Total property, plant, and equipment 11,412
 10,565
Other Property and Investments:    
Goodwill 5,967
 5,967
Equity investments in unconsolidated subsidiaries 1,609
 1,541
Other intangible assets, net of amortization of $100 and $34
at September 30, 2017 and December 31, 2016, respectively		 300
 366
Miscellaneous property and investments 21
 21
Total other property and investments 7,897
 7,895
Deferred Charges and Other Assets:    
Other regulatory assets, deferred 944
 973
Other deferred charges and assets 190
 170
Total deferred charges and other assets 1,134
 1,143
Total Assets $22,190
 $21,853
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.


SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity At September 30, 2017 At December 31, 2016 At September 30, 2018 At December 31, 2017
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $—
 $22
 $515
 $157
Notes payable 934
 1,257
 136
 1,518
Energy marketing trade payables 451
 597
 521
 546
Accounts payable 368
 348
Accounts payable —    
Affiliated 37
 21
Other 346
 425
Customer deposits 137
 153
 136
 128
Accrued taxes —        
Accrued income taxes —
 26
 —
 40
Other accrued taxes 70
 68
 61
 78
Accrued interest 66
 48
 66
 51
Accrued compensation 46
 58
 71
 74
Liabilities from risk management activities, net of collateral 28
 62
 28
 69
Other regulatory liabilities, current 126
 102
 132
 135
Accrued environmental remediation, current 54
 69
Other current liabilities 112
 108
 122
 159
Total current liabilities 2,392
 2,918
 2,171
 3,401
Long-term Debt 5,862
 5,259
 5,393
 5,891
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 2,214
 1,975
 944
 1,089
Deferred credits related to income taxes 930
 1,063
Employee benefit obligations 431
 441
 412
 415
Other cost of removal obligations 1,656
 1,616
 1,577
 1,646
Accrued environmental remediation, deferred 345
 357
 269
 342
Other regulatory liabilities, deferred 35
 51
Other deferred credits and liabilities 88
 127
 79
 118
Total deferred credits and other liabilities 4,769
 4,567
 4,211
 4,673
Total Liabilities 13,023
 12,744
 11,775
 13,965
Common Stockholder's Equity:        
Common stock, par value $0.01 per share —        
Authorized — 100 million shares        
Outstanding — 100 shares —
 —
 —
 —
Paid in capital 9,185
 9,095
 8,863
 9,214
Accumulated deficit (41) (12) (273) (212)
Accumulated other comprehensive income 23
 26
 33
 20
Total common stockholder's equity 9,167
 9,109
 8,623
 9,022
Total Liabilities and Stockholder's Equity $22,190
 $21,853
 $20,398
 $22,987
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.


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


THIRD QUARTER 2018 vs. THIRD 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 throughdistribution utilities in sevenfour states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland.Tennessee. Southern Company Gas and its subsidiaries are also involved in several other complementary businesses.
Southern Company Gas has four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (K)(L) to the Condensed Financial Statements herein and "BUSINESS – The Southern Company System – Southern Company Gas" in Item 1 of the Form 10-K.
Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain safety, to maintain constructive regulatory environments, to maintain and grow natural gas sales and number of customers, and to effectively manage and secure timely recovery of costs. Southern Company Gas hasThese costs include those related to projected long-term demand growth, environmental standards, reliability, natural gas, and capital expenditures, including updating and expanding the natural gas distribution systems. The natural gas distribution utilities have various regulatory mechanisms that 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 Southern Company Gas for the foreseeable future.
Merger, Acquisition, and Disposition Activities
On July 1, 2016,June 4, 2018, Southern Company Gas completed the Merger,stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which was accounted for by Southern Company usingincludes the acquisition methodfinal working capital adjustment. This disposition resulted in an estimated net loss of accounting whereby$73 million, which includes $39 million of income tax expense, the assets acquired and liabilities assumed were recognized at fair value ascalculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the acquisition date. Pushdown accountingtransaction, a goodwill impairment charge of $42 million was applied to create a new cost basis for Southern Company Gas assets, liabilities, and equity as ofrecorded during the acquisition date. Accordingly, the successor financial statements reflect a new basis of accounting and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods. See Note (I) to the Condensed Financial Statements herein for additional information relating to the Merger.
In September 2016, Southern Company Gas paid approximately $1.4 billion to acquire a 50% equity interest in SNG. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. Southern Company Gas recorded equity investment income of $28 million and $86 million from this investment in the successor thirdfirst quarter and year-to-date 2017, respectively, and $27 million in September 2016. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.
In October 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar. See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.2018.
On October 15, 2017,July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements forcompleted the salesales 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. Asbillion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of September 30, 2017,approximately $230 million and an after-tax gain of approximately $18 million, the net book valuecalculations of the assetswhich are expected to be disposed offinalized in the fourth quarter 2018.
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale was approximately $1.5 billion,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, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $0.5 billion$121 million and an after-tax gain of goodwill. approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.
The after-tax impacts of these dispositions included income tax expense on goodwill is not deductible for tax purposes and as a result,for which a deferred tax liability hashad not yet been provided for goodwill. Throughrecorded previously. See Note (J) to the completion of the sale, Condensed Financial Statements under "Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required" herein for ordinary business operations. The completion of each 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) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONSOVERVIEW – "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 Southern Company Gas' utilities in Illinois and Florida,Nicor Gas, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms,and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in Illinois and the gas marketing services customers primarily in Georgia and Illinois can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges at gas distribution operations and gas marketing services to reduce negative earnings impact in the event of warmer-than-normal weather, while retaining most of the earnings upside.upside for these businesses.
The number of customers atserved by gas distribution operations and energy customers at 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 Illinois.Ohio.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
See RESULTS OF OPERATIONS herein for additional information on these operating metrics.
Seasonality of Results
Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
RESULTS OF OPERATIONS
Net Income
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)(% change)
$11N/M
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$31 206.7 $(9) (3.0)
N/M - Not meaningful
Net income attributable to Southern Company Gas was $15 millionGas' net income for the third quarter 20172018 was $46 million compared to $4$15 million for the corresponding period in 2016. This2017. The increase was primarily due to $11 millionthe gains resulting from the sales of additional income from infrastructure replacement programsElizabethtown Gas, Elkton Gas, and base rate increases, net of associated depreciation,Florida City Gas and higher commercial activity at wholesale gas services, partially offset by derivative losses at wholesale gas services, disposition-related costs, and a $7 million2017 gain from the settlement of contractor litigation claims, partially offset by $12 million lowerclaims. Third quarter 2017 also included a deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.
For year-to-date 2018, net income at wholesale gas services. Also contributingwas $294 million compared to $303 million for the corresponding period in 2017. The decrease was primarily due to the increase was $24 millionnet loss resulting from the Southern Company Gas Dispositions and a goodwill impairment charge recorded during the first quarter 2018 in Merger-related expenses incontemplation of the third quarter 2016, partially offset by $23 millionsale of additional deferred income tax expense in the third quarter 2017.Pivotal Home
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Net Income Attributable to
Southern Company Gas		 $303
 $4
  $131
Net income attributable to Southern Company Gas for the successor year-to-date 2017 included $28 million of net income fromSolutions, derivative losses at wholesale gas services, disposition-related costs, and $38 million in earningslower gains from the SNG investment, netsettlement of related interest expense. Also includedcontractor litigation claims in net income for this2018 compared to the corresponding period was $29 million generatedin 2017, partially offset by higher commercial activity at wholesale gas services, additional revenues from the continued investment in infrastructure investments recovered through replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017, less the associated increasesincrease in depreciation. depreciation as well as base rate changes at gas distribution operations, and the lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. Year-to-date 2017 also included a deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Base Rate Cases" herein. These increases were partially offset by $23 million"Income Tax Matters" of additional deferred income tax expense.
Net income attributable to Southern Company Gas for the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 included $11 million and $42 million, respectively, in net losses from wholesale gas services. The successor period of July 1, 2016 through September 30, 2016 also included $16 million in earnings from the SNG investment, net of related interest expense. Also included in net income for these periods were $24 million and $41 million, respectively, of Merger-related expenses and $14 million of net income attributable to noncontrolling interest in the predecessor period of January 1, 2016 through June 30, 2016. As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in Item 7 of the successor periods.Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein.
Natural Gas Revenues, including Alternative Revenue Programs
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$14 2.7
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(40) (7.5) $60 2.2
In the third quarter 2017,2018, natural gas revenues, including alternative revenue programs, were $532$492 million compared to $518$532 million for the corresponding period in 2016.2017. For year-to-date 2018, natural gas revenues, including alternative revenue programs, were $2.8 billion compared to $2.7 billion for the corresponding period in 2017.
Details of the changes in natural gas revenues were as follows:
 Third Quarter 2017Third Quarter 2018 Year-to-Date 2018
 (in millions) (% change)(in millions) (% change) (in millions) (% change)
Natural gas – prior year $518
  
Natural gas revenues – prior year$532



$2,746



Estimated change resulting from –           
Infrastructure replacement programs and base rate increases 25
 4.8 %
Infrastructure replacement programs and base rate changes—

—

53

1.9
Gas costs and other cost recovery 1
 0.2
(16)
(3.0)
(24)
(0.9)
Mark-to-market adjustments at gas marketing services 3
 0.6
Weather1

0.2

17

0.6
Wholesale gas services (16) (3.1)17

3.2

46

1.7
Dispositions(*)
(43) (8.1) (30) (1.1)
Other 1
 0.2
1

0.2

(2)
—
Natural gas – current year $532
 2.7 %
Natural gas revenues – current year$492
 (7.5)% $2,806
 2.2 %
(*)
Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
The increase in natural gas revenue primarily relatesRevenues from infrastructure replacement programs and base rate changes increased for year-to-date 2018 due to gas distribution operationsoperations' continued investments recovered through infrastructure replacement programs and base rate increases as a result of continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, as well as the positive impact from the amortization of assets established in the application of acquisition accounting at gas marketing services. These increases werecases, partially offset by mark-to-revenue reductions for the impacts of the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements herein under "Regulatory Matters – Southern Company Gas" for additional information.
Revenues associated with gas costs and other cost recovery in the third quarter 2018 decreased due to reduced natural gas prices during the third quarter 2018 compared to the corresponding period in 2017 and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues associated with gas costs and other cost recovery for year-to-date 2018 decreased due to reduced natural gas prices during 2018 compared to the corresponding period in 2017, partially offset by increased
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


market losses from derivative instruments at wholesalevolumes of natural gas servicessold in 2018 as a result of colder weather. See "Cost of Natural Gas" herein for additional information.
Revenues increased due to colder weather in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and the gas marketing services due to changescustomers in natural gas pricesGeorgia and a decrease in commercial activity at wholesale gas services. For information on commercial activity at wholesale gas services, see "Segment Information – Wholesale Gas Services – Change in Commercial Activity" herein.Illinois. See the weather discussion herein for additional information.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Natural gas revenues $2,746
 $518
  $1,841
For the successor year-to-date 2017, natural gas revenues included recovery of $1.1 billion in cost of natural gas and $95 million in net revenuesRevenues from wholesale gas services net of $14 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues were $69 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues,increased primarily at Atlanta Gas Light effective March 1, 2017,due to increased commercial activity, partially offset by a $16 million decrease attributable to warmer-than-normal weather, net of hedging.
For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, natural gas revenues included recovery of $133 million and $755 million, respectively, in cost of natural gas, as well as $8 million and $32 million, respectively, in net losses from wholesale gas services. Also included in natural gas revenues for the predecessor period of January 1, 2016 through June 30, 2016 was a $7 million decrease attributable to warmer-than-normal weather, net of hedging.
derivative losses. See "Segment Information""Wholesale Gas Services" herein for additional information on wholesale gas services' revenues and losses.information.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverablegas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
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 non-HeatingHeating 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.
 Year-to-Date 2017
vs.
2016		 2017
vs.
normal		 Year-to-Date 2018 vs. 20172018 vs. normal
 
Normal(a)
 2017 2016 (warmer) (warmer) 
Normal(*)
20182017 coldercolder (warmer)
Illinois(b)
 3,817
 3,146
 3,353
 (6.2)% (17.6)% 3,758
3,858
3,146
 22.6%2.7 %
Georgia 1,631
 1,008
 1,449
 (30.4)% (38.2)% 1,578
1,542
1,008
 53.0%(2.3)%
(a)(*)Normal represents the 10-year average from January 1, 20072008 through September 30, 20162017 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.
(b)The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 3,580 for the first nine months from 1998 through 2007.
For the third quarters 2017 and 2016, the weather-related pre-tax income impact was immaterial.
Southern Company Gas hedged its exposure to warmer-than-normal weather at Nicor Gas in Illinois; therefore, the weather-related negative pre-tax income impact onIllinois for gas distribution operations was limited to $6 million ($3 million after tax) and $7 million ($5 million after tax)in Illinois and Georgia for year-to-date 2017 and 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services, to warmer-than-normal weatherwhich limited the negative income impacts reflected in Georgia and Illinois;the chart below.
 Gas Distribution Operations Gas Marketing Services
 Year-to-Date Year-to-Date
 20182017 20182017
 (in millions) (in millions)
Pre-tax$2
$(6) $(1)$(10)
After tax2
(3) (1)(6)
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for year-to-date 2017 and there was no impact for year-to-date 2016.
The following table provides the number of customers served by Southern Company Gas at September 30, 20172018 and 2016:2017:
September 30,  September 30,  
2017 2016 2017 vs. 20162018 2017 2018 vs. 2017
(in thousands, except market share %) (% change)(in thousands, except market share %) (% change)
Gas distribution operations(a)4,555
 4,522
 0.7 %4,177
 4,555
 (8.3)%
Gas marketing services(b)          
Energy customers(*)
756
 626
 20.8 %
Energy customers(c)
685
 756
 (9.4)%
Market share of energy customers in Georgia28.8% 29.4%  29.2% 28.8% 

Service contracts1,183
 1,189
 (0.5)%
(*)(a)
Includes total customers of approximately 404,000 at September 30, 2017 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" herein for additional information.
(b)On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions, which served approximately 1.2 million contracts prior to disposition. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.
(c)The decrease at September 30, 2018 is primarily due to approximately 70,000 fewer customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018. At September 30, 2017, there were approximately 140,000 customers as of September 30, 2017 that werein Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2017.
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.
Gas marketing services' market share in Georgia decreased at September 30, 2017Other Revenues
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(33) N/M $(40) (42.1)
N/M - Not meaningful
In the third quarter 2018, there were no other revenues compared to $33 million for the corresponding period in 2016 as a result of a highly competitive marketing environment,2017. For year-to-date 2018, other revenues were $55 million compared to $95 million for the corresponding period in 2017. Other revenues related to Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas expects to continue – Sale of Pivotal Home Solutions" herein for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.additional information.
Cost of Natural Gas
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$1 0.8
In the third quarter 2017, cost of natural gas was $134 million compared to $133 million for the corresponding period in 2016. This increase reflected 7% higher natural gas prices during the third quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Cost of natural gas $1,085
 $133
  $755
Cost of natural gas primarily reflected an increase of 38% in natural gas prices during the year-to-date 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(30) (22.4) $(32) (2.9)
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverablegas 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 approximately 79%75% and 83% of total cost of natural gas for the third quarter and year-to-date 2017 and will be recovered in this manner.2018, respectively. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas"Gas and Other Sales" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues" herein.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


In the third quarter 2018, cost of natural gas was $104 million compared to $134 million for the corresponding period in 2017. The decrease reflects $14 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in the third quarter 2018 as a result of fewer gas distribution operations customers, and a 3.2% decrease in natural gas prices during the third quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, cost of natural gas was $1.05 billion compared to $1.09 billion for the corresponding period in 2017. The decrease reflects $8 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in 2018 as a result of fewer gas distribution operations customers, as well as an 8.4% decrease in natural gas prices during 2018, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather compared to the corresponding period in 2017.
The following table details the volumes of natural gas sold during all periods presented.
Third Quarter 2017
vs.
2016		 Year-to-Date 2017
vs.
2016		Third Quarter2018
vs.
2017		 Year-to-Date2018
vs.
2017
2017 2016 % Change 2017 2016 % Change20182017 20182017
Gas distribution operations
(mmBtu in millions)
           
Gas distribution operations (mmBtu in millions)
   
Firm73
 71
 2.8 % 438
 467
 (6.2)%69
73
(5.5)% 503
438
14.8 %
Interruptible22
 22
 — % 71
 71
 — %22
22
— % 71
71
— %
Total95
 93
 2.2 % 509
 538
 (5.4)%91
95
(4.2)% 574
509
12.8 %
Gas marketing services
(mmBtu in millions)
           
Gas marketing services (mmBtu in millions)
 
  
Firm:            

  

Georgia3
 3
 — % 11
 25
 (56.0)%3
4
(25.0)% 25
20
25.0 %
Illinois1
 1
 — % 4
 8
 (50.0)%1
1
— % 9
8
12.5 %
Other emerging markets2
 2
 — % 7
 9
 (22.2)%
Interruptible:           
Large commercial and industrial3
 3
 — % 8
 10
 (20.0)%
Ohio1
2
(50.0)% 12
6
100.0 %
Other1
1
— % 3
4
(25.0)%
Interruptible large commercial and industrial3
3
— % 10
10
— %
Total9
 9
 — % 30
 52
 (42.3)%9
11
(18.2)% 59
48
22.9 %
Wholesale gas services
(mmBtu in millions/day)
           
Wholesale gas services (mmBtu in millions/day)
 

  

Daily physical sales6.3
 7.6
 (17.1)% 6.4
 7.6
 (15.8)%6.8
6.3
7.9 % 6.7
6.4
4.7 %
Cost of Other Operations and Maintenance ExpensesSales
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$(11) (5.1)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(7) N/M $(8) (40.0)
N/M - Not meaningful
In the third quarter 2017,2018, there was no cost of other operations and maintenance expenses were $205 millionsales compared to $216$7 million for the corresponding period in 2016. The decrease2017. For year-to-date 2018, cost of other sales was primarily$12 million compared to $20 million for the corresponding period in 2017. Cost of other sales related to $8 millionPivotal Home Solutions, which was sold on June 4, 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of expenses associated with certain benefit arrangements recorded in 2016, $2 million lower marketing expenses at gas marketing services, and a $3 million decrease in other employee benefit and incentive costs.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Other operations and maintenance $671
 $216
  $454
Other operations and maintenance expensesPivotal Home Solutions" herein for the successor year-to-date 2017 reflected increased compensation expenses due to timing, partially offset by low bad debt expense. For all periods presented, other operations and maintenance expenses primarily includes professional services, including pipeline compliance and maintenance and legal services, as well as compensation and benefit costs.additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


DepreciationOther Operations and AmortizationMaintenance Expenses
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$9 7.8
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$10 4.9 $55 8.1
In the third quarter 2017, depreciation2018, other operations and amortization was $125maintenance expenses were $216 million compared to $116$206 million for the corresponding period in 2016.2017. The increase was primarily due to $21 million of disposition-related costs and a $12 million increase in compensation and benefit costs, partially offset by a $24 million decrease related to the Southern Company Gas Dispositions and a $7 million decrease in bad debt expense at gas distribution operations.
For year-to-date 2018, other operations and maintenance expenses were $730 million compared to $675 million for the corresponding period in 2017. The increase was primarily due to $29 million of disposition-related costs, a $48 million increase in compensation and benefit costs, including a $12 million one-time increase for the adoption of a new paid time off policy to align with the Southern Company system, and an $11 million reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions. These increases were partially offset by an $11 million decrease related to the Southern Company Gas Dispositions and a $15 million decrease in 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," respectively, herein for additional information. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on the new paid time off policy.
Depreciation and Amortization
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(6) (4.8) $4 1.1
In the third quarter 2018, depreciation and amortization was $119 million compared to $125 million for the corresponding period in 2017. The decrease was primarily due to a $15 million decrease related to the Southern Company Gas Dispositions, partially offset by continued infrastructure investments recovered through replacement programs at gas distribution operations associated with additional plant in service primarily related to continued investment in infrastructure replacement programs.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Depreciation and amortization $370
 $116
  $206
Depreciation and amortization for the successor year-to-date 2017 included $29 million of additionallower amortization of intangible assets establishedas a result of fair value adjustments in the application of acquisition accounting primarily at gas marketing services, $21services.
For year-to-date 2018, depreciation and amortization was $374 million compared to $370 million for the corresponding period in additional depreciation2017. The increase was primarily due to continued infrastructure investments recovered through replacement programs at gas distribution operations, due to additional assets placed in service primarilypartially offset by a $20 million decrease related to continued investmentthe Southern Company Gas Dispositions and lower amortization of intangible assets as a result of fair value adjustments in infrastructure replacement programs, and $7 million fromacquisition accounting at gas marketing services.
See Note (J) to the acceleration of depreciation relating to certain assets.Condensed Financial Statements under "Southern Company Gas" herein for additional information on the Southern Company Gas Dispositions.
Taxes Other Than Income Taxes
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$(3) (10.3)
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 23.1 $17 12.1
In the third quarter 2017,2018, taxes other than income taxes were $26$32 million compared to $29$26 million for the corresponding period in 2016. The decrease2017. This increase primarily reflects establishinga $5 million credit in 2017 to establish a regulatory asset related to Nicor Gas' invested capital tax. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Riders" herein.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Taxes other than income taxes $140
 $29
  $99
Taxes other than income taxes in the successor periods reflected increased revenue-based taxes due to higher revenues at gas distribution operations during the successor periods.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


For year-to-date 2018, taxes other than income taxes were $157 million compared to $140 million for the corresponding period in 2017. This increase primarily reflects an $8 million increase in revenue tax expenses as a result of higher revenues, a $5 million credit in 2017 to establish a regulatory asset related to Nicor Gas' invested capital tax, and a $2 million increase in 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. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the Southern Company Gas Dispositions.
Gain on Dispositions, Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$353 N/M $317 N/M
N/M - Not meaningful
In the third quarter 2018, gain on dispositions, net of $353 million reflects the July 1, 2018 sales of the assets of Elizabethtown Gas and Elkton Gas, the July 29, 2018 sale of Pivotal Utility Holdings, and the final working capital adjustment for the sale of Pivotal Home Solutions. The year-to-date 2018 amount also reflects a $36 million pre-tax loss on the June 4, 2018 sale of Pivotal Home Solutions recorded during the second quarter 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Goodwill Impairment
Third Quarter 2018 vs. Third Quarter 2017Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)(% change)(change in millions)(% change)
$—N/M$42N/M
N/M - Not meaningful
For year-to-date 2018, a goodwill impairment charge of $42 million was recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Notes (A) and (J) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, herein for additional information.
Earnings from Equity Method Investments
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$3 10.3
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$2 6.3 $8 8.0
In the third quarter 2017,2018, earnings from equity method investments were $32$34 million compared to $29$32 million for the corresponding period in 2016. The increase was2017. For year-to-date 2018, earnings from equity method investments were $108 million compared to $100 million for the corresponding period in 2017. These increases were primarily due to higher earnings from SNG, PennEast Pipeline, and Horizon Pipeline.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Earnings from equity method investments $100
 $29
  $2
Earnings fromSouthern Company Gas' equity method investmentsinvestment in the successor year-to-date 2017 consisted of $86 million in earnings from SNG and $14 million in earnings from all other investments.
SNG. See Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K and Note (J)(K) to the Condensed Financial Statements under "Southern Company Gas – Equity Method Investments" herein for additional information.
Other Income (Expense), Net
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$9 100.0
In the third quarter 2017, other income (expense), net was $18 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a $14 million gain from the settlement of contractor litigation claims.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Other income (expense), net $26
 $9
  $5
The successor year-to-date 2017 reflects a $16 million gain from the settlement of contractor litigation claims. The successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 primarily represent the tax gross-up on contributions in aid of construction and AFUDC.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Interest Expense, Net of Amounts Capitalized
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$12 30.8
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$1 2.0 $25 17.2
In the third quarter 2017,For year-to-date 2018, interest expense, net of amounts capitalized was $51$170 million compared to $39$145 million for the corresponding period in 2016. The2017. This increase was primarily due to additional interest expense on new debt issuances.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Interest expense, net of amounts capitalized $145
 $39
  $96
The successor year-to-date 2017 and the period$20 million of July 1, 2016 through September 30, 2016 reflect additional interest expense on new debt issuances partially offset by reductionsand additional commercial paper borrowings, and a $5 million reduction in capitalized interest due to the Dalton Pipeline being placed in service in August 2017.
Other Income (Expense), Net
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(13) (68.4) $(9) (30.0)
In the third quarter 2018, other income (expense), net was $6 million compared to $19 million for the corresponding period in 2017. This decrease was primarily due to a $14 million gain from the settlement of $29contractor litigation claims in 2017.
For year-to-date 2018, other income (expense), net was $21 million andcompared to $30 million for the corresponding period in 2017. This decrease was primarily due to $9 million respectively, resultinglower gains from the fair value adjustmentsettlement of long-term debtcontractor litigation claims in acquisition accounting.2018 compared to the corresponding period in 2017.
See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" herein for additional information.
Income Taxes
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)(% change)
$45N/M
Third Quarter 2018 vs. Third Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$264 N/M $242 N/M
N/M - Not meaningful
In the third quarter 2017,2018, income taxes were $52$316 million compared to $7$52 million for the corresponding period in 2016. The increase reflects2017. For year-to-date 2018, income taxes were $475 million compared to $233 million for the corresponding period in 2017. These increases were primarily due to tax expense resulting from the Southern Company Gas Dispositions, including tax expense on the goodwill for which a deferred tax liability had not been previously provided, partially offset by a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. In addition, third quarter and year-to-date 2017 included a $23 million of additional deferred income tax expense associated withrelated to the enactment of the State of Illinois income tax legislation enacted during the third quarter 2017 and the allocation of new income tax apportionment factors in several states forstates.
See Notes (H) and (J) to the inclusion of Condensed Financial Statements under "Effective Tax Rate" and "Southern Company Gas into the consolidated Southern Company state tax filings, as well as higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL," respectively, herein for additional information.
  Successor  Predecessor
  Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions)  (in millions)
Income taxes $233
 $7
  $87
The successor year-to-date 2017 income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation and the allocation of new tax apportionment factors, as well as increased income taxes from higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.
Performance and Non-GAAP Measures
Prior to the Merger, Southern Company Gas evaluated segment performance using earnings before interest and taxes (EBIT), which includes operating income, earnings from equity method investments, and other income
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


(expense), net. EBIT excludes interest expense, net of amounts capitalized and income taxes (benefit), which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of Southern Company Gas' segments for the predecessor period, as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 presented herein is considered a non-GAAP measure. Southern Company Gas also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes that the presentation of segment EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minusless cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, and Merger-related expenses,gain on dispositions, net, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the consolidated statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from customer growth at gas distribution operations since
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of adjusted operating margin before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.
EBIT and adjustedAdjusted operating margin should not be considered alternativesan alternative to, or a more meaningful indicatorsindicator of, Southern Company Gas' operating performance than consolidated net income attributable to Southern Company Gas or 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.
 Successor  Predecessor
 Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through
June 30,
2016		Third Quarter 2018Third Quarter 2017 Year-to-Date 2018Year-to-Date 2017
 (in millions)  (in millions)(in millions)
Operating Income $68
 $12
 $555
 $12
  $321
$374
$67
 $810
$551
Other operating expenses(a)
 356
 396
 1,181
 396
  815
14
357
 986
1,185
Revenue taxes(b)
 (8) (8) (74) (8)  (56)(8)(8) (81)(74)
Adjusted Operating Margin $416
 $400
 $1,662
 $400
  $1,080
$380
$416
 $1,715
$1,662
(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, and Merger-related expenses.gain on dispositions, net.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
Segment Information
Adjusted operating margin, operating expenses, and net income for each segment is illustrated in the tables below. See Note (L) to the Condensed Financial Statements herein for additional information.
 Third Quarter 2018
Third Quarter 2017

 Adjusted Operating Margin(a)
 
Operating Expenses(a)(b)
 
Net Income (Loss)(b)
 
Adjusted Operating Margin(a)
 
Operating Expenses(a)
 Net Income (Loss)
 (in millions) (in millions)
Gas distribution operations$355

$(80)
$74

$379

$272

$52
Gas marketing services19

28

(8)
51

48

1
Wholesale gas services(8)
14

(18)
(25)
11

(23)
Gas midstream operations15

15

16

12

13

14
All other1

31

(18)
2

8

(29)
Intercompany eliminations(2)
(2)
—

(3)
(3)
—
Consolidated$380
 $6
 $46
 $416
 $349
 $15
(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 distribution operations and gas marketing services include the gain on dispositions, net. Net income for gas distribution operations and gas marketing services includes the gain on dispositions, net and the associated income tax expense. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


  Successor  Predecessor
  Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016
through
June 30,
2016
  (in millions)  (in millions)
Consolidated Net Income Attributable
to Southern Company Gas		 $15
 $4
 $303
 $4
  $131
Net income attributable to
noncontrolling interest (*)
   —
 —
 —
  14
Income taxes 52
 7
 233
 7
  87
Interest expense, net of amounts
capitalized		 51
 39
 145
 39
  96
EBIT $118
 $50
 $681
 $50
  $328
 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 (Loss)
 (in millions) (in millions)
Gas distribution operations$1,341

$540

$290

$1,329

$870

$223
Gas marketing services194

209

(71)
213

149

36
Wholesale gas services139

50

65

93

40

28
Gas midstream operations44

44

54

28

38

38
All other3

68

(44)
7

22

(22)
Intercompany eliminations(6)
(6)
—

(8)
(8)
—
Consolidated$1,715
 $905
 $294
 $1,662
 $1,111
 $303
(*)(a)See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
Segment Information
Adjusted operating margin, operating expenses, and Southern Company Gas' primary performance metric for each segment is illustrated in the tables below. See Note (K) to the Condensed Financial Statements herein for additional information.

Successor
 Third Quarter 2017
Third Quarter 2016

 Adjusted Operating
Operating
Net Income
Adjusted Operating
Operating
Net Income

Margin(*)

Expenses(*)

(Loss)
Margin(*)

Expenses(*)

(Loss)

(in millions)
(in millions)
Gas distribution operations$379

$271

$52

$353

$284

$27
Gas marketing services51

48

1

45

51

(4)
Wholesale gas services(25)
11

(23)
(8)
10

(11)
Gas midstream operations12

13

14

9

13

14
All other2

8

(29)
2

31

(22)
Intercompany eliminations(3)
(3)
—

(1)
(1)
—
Consolidated$416

$348

$15

$400

$388

$4
(*)Operating margin and operating expenses are adjusted for Nicor Gas'Gas revenue tax expenses, which are passed through directly to customers.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


 Successor  Predecessor
 Year-to-Date 2017 July 1, 2016 through
September 30, 2016		  January 1, 2016 through
June 30, 2016
  Adjusted Operating Operating Net Income Adjusted Operating Operating Net Income  Adjusted Operating Operating  
 
Margin(*)
 
Expenses(*)
 (Loss) 
Margin(*)
 
Expenses(*)
 (Loss)  
Margin(*)
 
Expenses(*)
 EBIT
 (in millions)  (in millions)
Gas distribution
operations		$1,329
 $866
 $223
 $353
 $284
 $27
  $911
 $560
 $353
Gas marketing
services		213
 149
 36
 45
 51
 (4)  190
 81
 109
Wholesale gas
services		93
 40
 28
 (8) 10
 (11)  (36) 33
 (68)
Gas midstream
operations		28
 38
 38
 9
 13
 14
  15
 24
 (6)
All other7
 22
 (22) 2
 31
 (22)  4
 65
 (60)
Intercompany
eliminations		(8) (8) —
 (1) (1) —
  (4) (4) —
Consolidated$1,662
 $1,107
 $303
 $400
 $388
 $4
  $1,080
 $759
 $328
(*)(b)
Operating marginexpenses 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 operatingOther Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.
(c)
Operating expenses are adjusted for Nicor Gas' revenuegas distribution operations and gas marketing services include the gain on dispositions, net. Net income for gas distribution operations and gas marketing services includes the gain on dispositions, net and the associated income tax expenses, which are passed through directlyexpense. See Note (J) to customers.the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest, maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit its exposure to weather changes within typical ranges in its natural gas distribution utilities' service territories.
SuccessorOn July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. See Note (J) under "Southern Company Gas" herein for additional information.
Third Quarter 2018 vs. Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017,2018, net income was $52increased $22 million, or 42.3%, compared to $27 million for the corresponding period in 2016. The2017. This increase in net incomeprimarily relates to an increase of $26a $352 million decrease in operating expenses, partially offset by a $24 million decrease in adjusted operating margin, a decrease of $13 million in operating expenses, and an increase of $11 million in other income (expense), net. The change in net income also includes an increase of $7 million in interest expense, net of amounts capitalized, and an increase of $18 million in income tax expense. The increase in adjusted operating margin primarily reflects $24 million in additional revenue from the continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. The decrease in operating expenses primarily reflects $18 million in rate credits provided to customers of Elizabethtown Gas in 2016 as a condition of the Merger, partially offset by $7 million in additional depreciation due to continued investment in infrastructure programs. The increase intotal other income (expense), net, primarily reflectsand a $14$288 million gain from the settlement of contractor litigation claims in 2017. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017. The increase in income tax expense relates primarilyexpense.
Excluding a $381 million decrease attributable to higher pre-tax earnings.
Successor Year-to-Date 2017
Net income of $223 million includes $1.3 billion in adjusted operating margin, $866 million inthe utilities sold during 2018, including the related gain, operating expenses increased $29 million, which primarily reflects additional depreciation due to additional assets placed in service and $23 millionincreased compensation and benefit costs, partially offset by a decrease in other income (expense), net, which resulted in EBIT of $486 million. Net income also includesbad debt expense. Excluding
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


$119a $29 million decrease in interest expense, net of amounts capitalized and $144 million in income tax expense. Adjustedadjusted operating margin reflects $69attributable to the utilities sold during 2018, adjusted operating margin increased $5 million, inwhich primarily reflects additional revenue from continued investment in infrastructure investments recovered through replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth,rates, partially offset by a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $21 million increase in depreciationlower rates and revenue deferrals for regulatory liabilities associated with additional assets placedTax Reform Legislation impacts. The decrease in service, as well as increased compensation expense, legal expenses, and pipeline compliance and maintenance activities. Otherother income (expense), net primarily reflects a $16$14 million gain from the settlement of contractor litigation claims. Interestclaims in 2017 and $7 million of additional interest expense primarily from the issuance of first mortgage bonds at Nicor Gas. Excluding a $314 million decrease attributable to the utilities sold in 2018, income tax expense decreased $26 million, primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income increased $67 million, or 30.0%, compared to the corresponding period in 2017. This increase primarily relates to a $12 million increase in adjusted operating margin and a $330 million decrease in operating expenses, partially offset by a $23 million decrease in total other income (expense), net, and a $252 million increase in income tax expense.
Excluding a $21 million decrease attributable to the utilities sold during 2018, adjusted operating margin increased $33 million, which primarily reflects additional revenue from continued infrastructure investments recovered through replacement programs and base rates and colder weather in 2018, partially offset by lower rates and revenue deferrals for regulatory liabilities associated with Tax Reform Legislation impacts. Excluding a $378 million decrease attributable to the impactutilities sold during 2018, including the related gain, operating expenses increased $48 million, which primarily reflects $27 million of intercompany promissory notes executedadditional depreciation primarily due to additional assets placed in December 2016service and increased compensation and benefit costs, partially offset by a decrease in bad debt expense. The decrease in other income (expense), net primarily reflects $16 million of additional interest expense primarily from the issuance of first mortgage bonds at Nicor Gas on August 10, 2017.
Successor Periodand commercial paper borrowings and $9 million lower gains from the settlement of July 1, 2016 through September 30, 2016
Net income of $27 million includes $353 millioncontractor litigation claims during 2018 compared to the corresponding period in adjusted operating margin, $284 million in operating expenses, including $18 million in rate credits provided to customers, and $6 million in other income (expense), net, which resulted in EBIT of $75 million. Net income also includes $32 million in interest expense and $16 million in income tax expense.
Predecessor Period of January 1, 2016 through June 30, 2016
EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expenses, and $2 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth,2017, partially offset by an increase in interest income. Excluding a $7$307 million negative impactdecrease attributable to the utilities sold in 2018, income tax expense decreased $55 million, primarily due to a lower federal income tax rate and the flowback of warmer-than-normal weather, netexcess deferred taxes as a result of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.the Tax Reform Legislation.
Gas Marketing Services
Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets, including warranty sales.markets. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.
SuccessorOn June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions to American Water Enterprises LLC. See Note (J) under "Southern Company Gas" herein for additional information.
Third Quarter 2018 vs. Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017,2018, net income was $1decreased $9 million compared to a net loss of $4 million for the corresponding period in 2016. The increase in net income2017. This decrease primarily relates to a $6$32 million increasedecrease in adjusted operating margin, andpartially offset by a $3$20 million decrease in operating expenses. The change in net income also includes increases of $1 million and $3 million in interest expense and income tax expense, respectively. Adjusted operating margin primarily reflects a $3 million decrease in unrealized hedge losses, net of recoveries,expenses and a $4 million increase from the elimination of deferred revenuedecrease in the third quarter 2016 from the application of acquisition accounting. Operating expenses reflect decreased amortization of intangible assets established in the application of acquisition accounting.income tax expense.
Successor Year-to-Date 2017
Net income of $36Excluding a $26 million includes $213 million indecrease attributable to Pivotal Home Solutions, adjusted operating margin decreased $6 million, which primarily reflects a $5 million decrease due to the timing of revenue recognition for fixed and $149 millionguaranteed bill revenue as a result of adopting a new revenue recognition standard. The decrease in operating expenses which resulted in EBIT of $64 million. Net income also includes $4primarily reflects a $19 million in interest expense and $24 milliondecrease attributable to Pivotal Home Solutions. The decrease in income tax expense. Adjusted operating margin reflectsexpense was driven by a $10 million negative impact of warmer-than-normal weather, net of hedging, and $7 million in unrealized hedge losses, net of recoveries. Operating expenses include $30 million in additional amortization of intangible assets established in the application of acquisition accounting.
Successor Period of July 1, 2016 through September 30, 2016
Nethigher pretax loss, of $4 million includes $45 million in adjusted operating margin and $51 million in operating expenses, which resulted inpartially offset by a loss before interest and taxes of $6 million. Also included in net loss is $2 million inlower federal income tax benefit.rate.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Predecessor Period of January 1, 2016 through June 30, 2016Year-to-Date 2018 vs. Year-to-Date 2017
EBIT of $109For year-to-date 2018, net income decreased $107 million includes $190compared to the corresponding period in 2017. This decrease primarily relates to a $19 million decrease in adjusted operating margin, and $81a $60 million increase in operating expenses. Adjustedexpenses, and a $28 million increase in income tax expense.
Excluding a $33 million decrease attributable to Pivotal Home Solutions, adjusted operating margin reflects $9 million in unrealized hedge gains. Earnings in the predecessor period includeincreased $14 million, which primarily reflects colder weather in 2018. Excluding a $62 million increase attributable to noncontrolling interest.Pivotal Home Solutions that includes the loss on disposition and the goodwill impairment charge, operating expense decreased $2 million primarily due to a decrease in depreciation and amortization primarily due to lower amortization of intangible assets as a result of fair value adjustments recorded during acquisition accounting, partially offset by higher bad debt expenses and compensation and benefit costs. The increase in income tax expense was driven by higher pretax earnings, partially offset by a lower federal income tax rate.
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.
SuccessorThird Quarter 2018 vs. Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017,2018, net loss was $23decreased $5 million, or 21.7%, compared to a net loss of $11 million for the corresponding period in 2016. The2017. This increase in net lossprimarily relates primarily to a $17 million decreaseincrease in adjusted operating margin, partially offset by ana $3 million increase ofin operating expenses and an $8 million decrease in income tax benefit. Details of the increase in adjusted operating margin are provided in the table below. The increase in operating expenses primarily reflects higher compensation and benefit expense. The decrease in income tax benefit due to higher losses. The decrease in adjusted gross margin includes $22 million in additional mark-to-market losses andwas driven by a $7 million decrease in gains from commercial activity,lower pretax loss, partially offset by a $12 million positive impact from the amortization of liabilities recorded in the application of acquisition accounting.lower federal income tax rate.
SuccessorYear-to-Date 2018 vs. Year-to-Date 2017
NetFor year-to-date 2018, net income of $28increased $37 million, includes $93or 132.1%, compared to the corresponding period in 2017. This increase primarily relates to a $46 million increase in adjusted operating margin and $40a $2 million in operating expenses, which resulted in EBIT of $53 million. Net income also includes $5 million in interest expense and $20 milliondecrease in income tax expense.
Successor Periodexpense, partially offset by a $10 million increase in operating expenses. Details of July 1, 2016 through September 30, 2016
Net loss of $11 million includes $(8) millionthe increase in adjusted operating margin and $10 millionare provided in the table below. The increase in operating expenses which resulted in a loss before interestprimarily reflects higher compensation and taxes of $17 million. Also included in net loss is $1 million in interest expense and $7 millionbenefit expense. The decrease in income tax benefit.expense was driven by a lower federal income tax rate.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.
 Third Quarter 2018Third Quarter 2017 Year-to-Date 2018Year-to-Date 2017
 (in millions)
Commercial activity recognized$33
$3
 $212
$80
Gain (loss) on storage derivatives(3)4
 (2)13
Gain (loss) on transportation and forward commodity derivatives(33)(22) (70)14
Purchase accounting adjustments to fair value inventory and contracts(5)(10) (1)(14)
Adjusted operating margin$(8)$(25) $139
$93
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.
 Successor  Predecessor
 Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 July 1, 2016 through September 30, 2016  January 1, 2016
through
June 30,
2016
 (in millions)  (in millions)
Commercial activity recognized$3
 $10
 $80
 10
  $34
Gain (loss) on storage derivatives4
 11
 13
 11
  (38)
Gain (loss) on transportation and forward
commodity derivatives		(22) (7) 14
 (7)  (31)
LOCOM adjustments, net of current period
recoveries		—
 —
 —
 —
  (1)
Purchase accounting adjustments(10) (22) (14) (22)  —
Adjusted Operating Margin$(25) $(8) $93
 $(8)  $(36)
Change in Commercial Activity
The increase in commercial activity at wholesalein the third quarter and year-to-date 2018 compared to the corresponding periods in 2017 was primarily due to natural gas services includes recognition of storageprice volatility that was generated by favorable weather and transportation values that were generateda corresponding increase in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes and build-out of new U.S. pipeline infrastructure, alongcoupled with increases indecreased natural gas supply, caused low volatility and a tightening of locational or transportation spreads in 2017, negatively impacting the amount of commercial activity revenues generated relative to demand fees for contracted pipeline transportation and storage capacity, and minimum sharing under asset management agreements. However, as natural gas prices and forward storage or time spreads increased, wholesale gas services was able to capture higher storage values that it expects to recognize as commercial activity revenues when natural gas is physically withdrawn from storage. Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.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. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first nine months of 2017, forwardForward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2018 resulted in storage derivative gains.losses. Transportation and forward commodity derivative gainslosses in 2018 are primarily the result of narrowingwidening transportation basis spreads due to some reduction in supply constraints resulting from new U.S. pipeline infrastructure and increases in natural gas supply and warmer-than-normalfavorable weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.
Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


charges, but are net of theand exclude estimated impact of profit sharing under its 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 September 30, 2017.2018. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
 Storage withdrawal schedule  
 
Total storage
(WACOG $2.67)
 
Expected net operating gains(a)
 
Physical transportation transactions – expected net operating gains (losses)(b)
 (in mmBtu in millions) (in millions) (in millions)
201722.0
 $4
 $(13)
2018 and thereafter40.0
 17
 28
Total at September 30, 201762.0
 $21
 $15
 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)
201810.2
 $4
 $5
2019 and thereafter26.1
 9
 65
Total at September 30, 201836.3
 $13
 $70
(a)At September 30, 2018, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.51 per mmBtu.
(b)Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.
(b)(c)Represents the periods associated with the transportation derivative gains and (losses) during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.
The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Gas Midstream Operations
Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note (J)(K) to the Condensed Financial Statements herein and NotesNote 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.
SuccessorThird Quarter 2018 vs. Third Quarter 2017 vs. Third Quarter 2016
In both the third quarter 2017 and2018, net income increased $2 million, or 14.3%, compared to the corresponding period in 2016 net income was $14 million. Net income reflects2017. This increase primarily relates to a $3 million increase in adjusted operating margin primarily due to the Dalton Pipeline being placed in service in August 2017 and a $4$2 million net increase in earnings from equity method investments atin SNG and PennEast Pipeline, and Horizon Pipeline. The change in net income also includespartially offset by a $9$2 million increase in interest expense net of amountsprimarily due to a reduction in capitalized and a $2 million decreaseinterest after the Dalton Pipeline was placed in income taxes. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016.service.
SuccessorYear-to-Date 2018 vs. Year-to-Date 2017
NetFor year-to-date 2018, net income of $38increased $16 million, includes $28or 42.1%, compared to the corresponding period in 2017. This increase primarily relates to a $16 million increase in adjusted operating margin $38primarily due to the Dalton Pipeline being placed in service in August 2017, partially offset by a reduction in storage revenues. The increase in net income also relates to an $8 million in operating expenses, $97 millionnet increase in earnings from equity method investments consisting primarily of earnings from equity method investments at SNG, and $3partially offset by a $7 million in other income (expense), net, which resulted in EBIT of $90 million. Also included in net income are $25 millionincrease in interest expense and $27 millionprimarily due to a reduction in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
Net income of $14 million includes $9 millioncapitalized interest after the Dalton Pipeline was placed in adjusted operating margin, $13 million in operating expenses, $28 million in earnings from equity method investments, consisting primarily of earnings from equity method
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of $25 million. Also included in net income is $11 million in income tax expense.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $6 million includes $15 million in adjusted operating margin, $24 million in operating expenses, and $3 million of other income (expense), net.service.
All Other
All other includes Southern Company Gas' investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.
SuccessorThird Quarter 2018 vs. Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017,2018, net loss was $29decreased $11 million compared to $22 million in the corresponding period in 2016. The increase2017. This decrease includes a $27 million decrease in income tax expense primarily related to the 2017 enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states and a $4 million decrease in interest expense, net of amounts capitalized primarily due to decreased interest expense on lower commercial paper borrowings, partially offset by $21 million of disposition-related costs and a lower federal income tax rate in 2018.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net loss increased $22 million compared to the corresponding period in 2017. This increase primarily reflects a $23$46 million decreaseincrease in operating expenses and a decrease of $2 million in other income (expense), net. Net loss also reflected a $6 million increase in interest expense, net of amounts capitalized, and an increase of $34 million in income taxes. The decrease in operating expenses reflects a $35 million decrease in Merger-related expenses, partially offset by a $10$27 million decrease in income tax expense. The increase in operating expenses primarily reflects $29 million of disposition-related costs and a $12 million increase in other operations and maintenance expenses and a $3 million increasecompensation expense resulting from the accelerationadoption of depreciation relating to certain assets. Interest expense decreased as a resultthe new paid time off policy. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of intercompany promissory notes executedSouthern Company Gas in December 2016.Item 7 of the Form 10-K for additional information on the new paid time off policy. The increasedecrease in income taxestax expense was primarily reflects additional deferred income tax expenses associated withrelated to the 2017 enactment of the State of Illinois income tax legislation enacted during the third quarter 2017, as well as the allocation ofand new income tax apportionment factors in several states, for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.
Successor Year-to-Date 2017, Successor Period of July 1, 2016 through September 30, 2016, and Predecessor Period of January 1, 2016 through June 30, 2016
For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, Merger-related expenses were $35 million and $56 million, respectively. There were no Merger-related expenses during the successor year-to-date 2017. In the successor year-to-date 2017, depreciation and amortization includes $7 million from the acceleration of depreciation relating to certain assets. Interest expense, net of amounts capitalized was $8 million, $6 million, and $34 million, respectively, in the successor year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. Income taxes were $18 million in the successor year-to-date 2017 andpartially offset by a lower federal income tax benefit was $11 million and $35 million, respectively,rate in the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016. In the successor year-to-date 2017, income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017 and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.2018.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Segment Reconciliations
Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor third quarter and year-to-date 2017, and operating income to adjusted operating margin for all periods presented,the third quarter 2018 and 2017 are reflected in the following tables. See Note (K)(L) to the Condensed Financial Statements herein for additional information.

Successor

Third Quarter 2017

Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated

(in millions)
Consolidated Net Income
(Loss)		$52
$1
$(23)$14
$(29)$—
$15
Income taxes (benefit)34
1
(15)9
23
—
52
Interest expense, net of
amounts capitalized		39
1
2
9
—
—
51
EBIT$125
$3
$(36)$32
$(6)$—
$118
  Successor
  Third Quarter 2016
  Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
  (in millions)
Consolidated Net Income
(Loss)		 $27
$(4)$(11)$14
$(22)$—
$4
Income taxes (benefit) 16
(2)(7)11
(11)—
7
Interest expense, net of
amounts capitalized		 32
—
1
—
6
—
39
EBIT $75
$(6)$(17)$25
$(27)$—
$50
 Successor
 Year-to-Date 2017
 Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
 (in millions)
Consolidated Net Income
(Loss)		$223
$36
$28
$38
$(22)$—
$303
Income taxes144
24
20
27
18
—
233
Interest expense, net of
amounts capitalized		119
4
5
25
(8)—
145
EBIT$486
$64
$53
$90
$(12)$—
$681
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Successor

Third Quarter 2017Third Quarter 2018

Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidatedGas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated

(in millions)(in millions)
Operating Income (Loss)$108
$3
$(36)$(1)$(6)$—
$68
$435
$(9)$(22)$—
$(30)$—
$374
Other operating expenses(a)
279
48
11
13
8
(3)356
(72)28
14
15
31
(2)14
Revenue tax expense(b)
(8)—
—
—
—
—
(8)(8)—
—
—
—
—
(8)
Adjusted Operating
Margin		$379
$51
$(25)$12
$2
$(3)$416
$355
$19
$(8)$15
$1
$(2)$380
Successor
Third Quarter 2016Third Quarter 2017
Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidatedGas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
(in millions)(in millions)
Operating Income (Loss)$69
$(6)$(18)$(4)$(29)$—
$12
$107
$3
$(36)$(1)$(6)$—
$67
Other operating expenses(a)
292
51
10
13
31
(1)396
280
48
11
13
8
(3)357
Revenue tax expense(b)
(8)—
—
—
—
—
(8)(8)—
—
—
—
—
(8)
Adjusted Operating
Margin		$353
$45
$(8)$9
$2
$(1)$400
$379
$51
$(25)$12
$2
$(3)$416
Successor
Year-to-Date 2017Year-to-Date 2018
Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidatedGas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
(in millions)(in millions)
Operating Income (Loss)$463
$64
$53
$(10)$(15)$—
$555
$801
$(15)$89
$—
$(65)$—
$810
Other operating expenses(a)
940
149
40
38
22
(8)1,181
621
209
50
44
68
(6)986
Revenue tax expense(b)
(74)—
—
—
—
—
(74)(81)—
—
—
—
—
(81)
Adjusted Operating
Margin		$1,329
$213
$93
$28
$7
$(8)$1,662
$1,341
$194
$139
$44
$3
$(6)$1,715
Predecessor
January 1, 2016 through June 30, 2016Year-to-Date 2017
Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidatedGas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
(in millions)(in millions)
Operating Income (Loss)$351
$109
$(69)$(9)$(61)$—
$321
$459
$64
$53
$(10)$(15)$—
$551
Other operating expenses(a)
616
81
33
24
65
(4)815
944
149
40
38
22
(8)1,185
Revenue tax expense(b)
(56)—
—
—
—
—
(56)(74)—
—
—
—
—
(74)
Adjusted Operating Margin$911
$190
$(36)$15
$4
$(4)$1,080
$1,329
$213
$93
$28
$7
$(8)$1,662
(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, and Merger-related expenses.gain on dispositions, net.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of itsSouthern Company Gas' primary business of natural gas distribution and its complementary businesses in the gas marketing services, wholesale gas services, and gas midstream operations sectors. These factors include Southern Company Gas' ability to maintain a constructive regulatory 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, Southern Company Gas'its ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices.
Future earnings in the near term will depend, in part, upon maintainingbe driven by customer growth and growing sales and customers which are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
On July 6, 2017, the State of Illinois enacted tax legislation that repealed its non-combination tax rule and increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation required Southern Company Gas to increase accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect these changes, $15 million of which was expensed and $9 million was recorded as a regulatory asset. In addition, during the third quarter 2017, Southern Company calculated new apportionment factors in several states to include Southern Company Gas in its consolidated tax filings, which resulted in $8 million of additional deferred income tax expenses.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. The execution of the asset purchase agreements triggered an interim assessment of goodwill, which is currently being performed with the assistance of a third-party valuation specialist. The preliminary results of this valuation indicate that the estimated fair values of the reporting units with goodwill exceed their carrying amounts and are not at risk of impairment. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sales.
Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of its gas marketing services and wholesale gas services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability. Over the longer-term,longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further, if economic conditions continue to improve, including the new housing market, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.
As part of its business strategy, Southern Company Gas regularly considers and evaluates joint development arrangements as well as acquisitions and dispositions of businesses and assets.
On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC. Prior to its disposition, 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 provided certain administrative and operational services through November 4, 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. Prior to these dispositions, 2018 net income attributable to Elizabethtown Gas and Elkton Gas was $45 million. 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. Prior to its disposition, 2018 net income attributable to Florida City Gas was $29 million. 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.
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 SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


ForSee Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information relating toon these issues, see "Risk Factors"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 in Item 1AGas' operations. The impact of the Form 10-K.
any such changes cannot be determined at this time. Environmental Matters
Compliancecompliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed.basis. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for natural gas.
Environmental Remediation
Subsequent to the disposition of Elizabethtown Gas, Southern Company Gas is subject to environmental remediation liabilities associated with 40 former manufactured gas plant sites in four different states. Accrued environmental remediation costs decreased at September 30, 2018 primarily due to the disposition of $85 million that related to Elizabethtown Gas.
See Note (B) under "Environmental"Environmental Matters– Environmental Remediation" to the Condensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
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 (LDNR). 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 September 30, 2017, 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 the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. 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 material impact on Southern Company Gas' financial statements.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS –FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 and Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information regarding the Dalton Pipeline project.information.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.
On October 13, 2017, theThe Atlantic Coast Pipeline project received FERC approval.has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
Riders
Nicor Gas has established a variable tax cost adjustment rider, which was approved byOn April 19, 2018, the Illinois Commission effective July 16, 2017.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, via bill credits, began on July 1, 2018 related to the invested capital tax imposed onimpacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas through an annual true-up and reconciliation mechanism based on amountsGas' approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.rehearing request discussed herein under "Settled Base Rate Cases."
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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


Base Rate Cases
Settled Base Rate Cases
On February 21, 2017,23, 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 Rate Adjustment Mechanism (GRAM)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 $20traditional 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 increase in annual base rate revenues for Atlanta Gas Light,became effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approvedMay 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 10.75%9.8% were not addressed in the rehearing and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized byremain unchanged. The impact of the Georgia PSCTax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under Atlanta Gas Light's STRIDE program, which include"Riders."
On October 15, 2018, the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be includedTennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increaserevenues, which was based on a projected 12-month test year ending March 31, 2017June 30, 2019 and a ROE of 10.25%9.80%. The new rates became effective November 1, 2018.
Other
The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On JuneAugust 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate revenues, effective July 1, 2017, based onand the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits, for the related amounts deferred as a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for information on the proposed sale of Elizabethtown Gas.
Pending Base Rate Cases
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues.regulatory asset. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The IllinoisVirginia Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.
On March 31, 2017,filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase inGas' annual base rate revenues including $13 million relatedwould be reduced by $14 million. 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. The sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy did not impact the asset management agreement between wholesale gas services and Florida City Gas, which will remain in effect until its original maturity of March 31, 2019. See Note (J) to the recoveryCondensed 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 investments underSouthern Company Gas in Item 7 of the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for aForm 10-K.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.
On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
The ultimate outcome of these pending base rate cases 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.
Nicor Gas
In 2014, Excluding the Illinois Commission approved Nicor Gas' nine-year regulatorynatural gas distribution utilities sold in July 2018, infrastructure program, Investingexpenditures incurred in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.2018 were as follows:
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.
UtilityProgramYear-to-Date 2018
  (in millions)
Nicor GasInvesting in Illinois$267
Atlanta Gas LightGeorgia Rate Adjustment Mechanism (GRAM) infrastructure spending217
Virginia Natural GasSteps to Advance Virginia's Energy33
Total $517
See "MANAGEMENT'S DISCUSSION AND ANALYSIS Base Rate Cases–" herein FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K for additional information.
ElizabethtownIncome Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas
In 2013, in Item 7 of the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extensionForm 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the SAVE program,Condensed Financial Statements under which Virginia Natural"Regulatory Matters – Southern Company Gas invested $21 million during," and Note (H) to the first nine months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' SAFE program in 2015. UnderCondensed Financial Statements herein for information regarding the program, Florida City Gas invested $9 million during the first nine months of 2017.Tax Reform Legislation and related regulatory actions.
Other Matters
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


ordinary course of business. The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas and Nicor Inc. were defendantsowns a 50% interest in a putative class action initially filedplanned LNG liquefaction and storage facility in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement,Jacksonville, Florida, which was finalized and effective on April 3, 2017. The settlement did not haveplaced in service in October 2018. This facility is outfitted with a material impact on Southern Company Gas' financial statements.2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates related to Utility Regulation, Pushdown of Acquisition Accounting, Assessment of Assets, Derivatives and Hedging Activities, Pension and Other Postretirement Benefits, and Contingent Obligations.estimates.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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.
information regarding ASU No. 2016-02, In 2014,Leases (Topic 842) (ASU 2016-02). See Note (A) to the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidanceCondensed Financial Statements herein for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosuresinformation regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Company Gas expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. Southern Company Gas expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.recently adopted accounting standards.
Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company Gas' financial statements. In addition, the power
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company Gas has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company Gas' financial statements, Southern Company Gas will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017,2016, the FASB issued ASU No. 2017-04, Intangibles – Goodwill2016-02, which requires lessees to recognize on the balance sheet a lease liability and Other (Topic 350): Simplifyinga right-of-use asset for all leases. ASU 2016-02 also changes the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removesrecognition, measurement, and presentation of expense associated with leases and provides clarification regarding the requirement to compare the implied fair valueidentification of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.
On March 10, 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 othercertain components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost componentcontracts that would represent a lease. The accounting required by lessors is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations.relatively unchanged. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company Gas' financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 2017-122016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlySouthern Company Gas will adopt the new standard effective January 1, 2019.
Southern Company Gas has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption permitted. date of January 1, 2019, without restating prior periods. Southern Company Gas expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company Gas expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company Gas also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Southern Company Gas is evaluatingcontinuing to complete the standardimplementation of an information technology system to track and expectsaccount for its leases and of changes to early adoptits internal controls and accounting policies to support the accounting for leases under ASU 2017-12 effective January 1, 2018. The2016-02. Southern Company Gas has substantially completed its lease inventory and determined its most significant leases involve real estate and fleet vehicles. While Southern Company Gas has not yet determined the ultimate impact, adoption of ASU 2017-122016-02 is not expected to have aresult in recording lease liabilities and right-of-use assets on Southern Company Gas' balance sheet each totaling approximately $90 million, with no material impact on Southern Company Gas' financial statements.statement of income.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. As a result of the Merger that closed on July 1, 2016, the results reported herein include disclosure of the successor third quarter and year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Southern Company Gas' financial condition remained stable at September 30, 2017.2018. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Due to the increased working capital requirements associated with Nicor Gas' Investing in Illinois infrastructure replacement program, since 2015, Nicor Gas has temporarily ceased distributing dividends to Southern Company Gas. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As ofAt September 30, 2017,2018, the amount of subsidiary retained earnings and net income availablerestricted to dividend totaled $752$786 million. These restrictionsThis restriction did not have any impact on Southern Company Gas' ability to meet its cash obligations, nor does management expect such restrictions to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Net cash provided from (used for) operating activities totaled $1.1 billion$736 million for the successor first nine months of 2017, $(342)2018, a decrease of $410 million forfrom the successorcorresponding period of July 1, 2016 through September 30, 2016, and $1.1 billion forin 2017. The decrease was primarily due to higher income tax payments due to the predecessor period of January 1, 2016 through June 30, 2016. These cash flows were primarily drivennet taxable gains from the Southern Company Gas Dispositions, partially offset by the saleincreased volumes of natural gas inventorysold during the respective periods.
Net cash used for investing activities totaled $1.2 billion for the successor first nine months of 2017, primarily due2018 as a result of colder weather compared to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines. Net cash used for investing activities totaled $1.7 billion for the successor period of July 1, 2016 through September 30, 2016 and $559 million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and the acquisition of Southern Company Gas' ownership interest in SNG in September 2016.
prior year. Net cash provided from financinginvesting activities totaled $45 million$1.4 billion for the successor first nine months of 2017,2018 primarily due to proceeds from debt issuances and capital contributions fromthe Southern Company Gas Dispositions, partially offset by net repayments of commercial paper borrowingsgross property additions primarily related to utility capital expenditures and common stock dividend payments to Southern Company. Net cash provided from (used for) financing activities totaled $2.1 billion for the successor period of July 1, 2016pre-approved rider and infrastructure investments recovered through September 30, 2016 and $(558) million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to net repayments of commercial paper borrowings, the redemption of long-term debt, and common stock dividend payments to shareholders, partially offset by proceeds from debt issuances. The successor period of July 1, 2016 through September 30, 2016 also includes capital contributions from Southern Company to fund the investment in SNG. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Significant balance sheet changes at September 30, 2017 include an increase of $847 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs an increaseat gas distribution operations as well as capital contributed to equity method investments in long-term debtpipelines. Net cash used for financing activities totaled $2.2 billion for the first nine months of $603 million2018 primarily due to $450 million of senior notes and $200 million of first mortgage bonds at Nicor Gas issued in May 2017 and August 2017, respectively, and a decrease of $323 million in notes payable related primarily to net repayments of commercial paper borrowings, at Nicor Gas.the redemption of gas facility revenue bonds, and common stock dividend payments and return of capital to Southern Company, partially offset by proceeds from the issuance of first mortgage 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 nine months of 2018 include $2.8 billion and $404 million in total assets and liabilities sold, respectively, associated with the Southern Company Gas Dispositions as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas," a decrease of $109 million in natural gas for sale due to the use of stored natural gas, and a $1.4 billion decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include an increasedecreases of $239$63 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in serviceaccounts payable as well as the impact of State of Illinois tax legislation, and decreases of $196$109 million and $146$25 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.prices and an increase of $714 million in total property, plant, and equipment primarily due to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements for its infrastructure programs, scheduledand contractual obligations. Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $350 million will be required through September 30, 2019 to fund maturities of long-term debt and the related interest, as well as pipeline charges, storage capacity, and gas supply, operating leases, asset management agreements, standby letters of credit and performance/surety bonds, financial derivative obligations, pension and other postretirement benefit plans, and other purchase commitments, primarily related to environmental remediation liabilities. There are no scheduled maturities of long-term debt through September 30, 2018.debt. See "Sources of Capital" herein for additional information.
The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, borrowings from financial institutions, and borrowings and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, 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.
At September 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $645$469 million primarily as a result of $934$515 million in notes payable.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 intends to utilize operating cash flows, commercial paper, and debtexternal securities issuances, as market conditions permit, as well asborrowings from financial institutions, borrowings and equity contributions from Southern Company, and the proceeds from its dispositions to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


At September 30, 2017,2018, Southern Company Gas had approximately $21$56 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 20172018 were as follows:
Company Expires 2022 UnusedExpires 2022 Unused
 (millions)(in millions)
Southern Company Gas Capital(a) $1,200
 $1,161
$1,400
 $1,395
Nicor Gas 700
 700
500
 500
Total(b) $1,900
 $1,861
$1,900
 $1,895
Additionally, Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds totaling $200 million have been issued.
(a)Southern Company Gas guarantees the obligations of Southern Company Gas Capital.
(b)Pursuant to the credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
See Note 6 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E)(F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
In May 2017,The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations may be adjusted.
The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each facility)the Facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017,2018, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to Southern Company Gas.
Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.
Details of commercial papershort-term borrowings were as follows:
Commercial Paper at September 30, 2017 
Commercial Paper During the Period(*)
Short-Term Debt at
September 30, 2018
 
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$836
 1.5% $680
 1.5% $838
$—
 —% $18
 2.4% $573
Nicor Gas98
 1.3
 40
 1.3
 120
136
 2.4% 67
 2.3% 154
Short-term loans:         
Southern Company Gas—
 —% 12
 2.8% 276
Total$934
 1.5% $720
 1.5%  $136
 2.4% $97
 2.3%  
(*)Average and maximum amounts are based upon daily balances during the successor three-month period ended September 30, 2017.2018.
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, prior to its sale, 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


$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 requirementsrequirement under these contracts at September 30, 2017 were $122018 was approximately $10 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated creditSeptember 28, 2018, Fitch assigned a negative rating outlook forto the ratings of Southern Company and certain of its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas).
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from stableoperations to negative.debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
Financing Activities
The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of September 30, 2017,2018, the non-principal components totaled $523$469 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
In December 2016,On January 4, 2018, Southern Company Gas executed intercompanyissued a floating rate promissory notesnote to further allocateSouthern Company in an aggregate principal amount of $100 million bearing interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allowbased on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.
Prior to calculate net income, which is its performance measure subsequent tosale, in the Merger, at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of Series 2017A 4.40% Senior Notes duegas 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. In July 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 2047.days' demand by the bank. The proceeds of the loan were used to repay short-term debt. In July 2018, Southern Company Gas' short-term indebtedness and for general corporate purposes.Gas Capital repaid this loan.
In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.
In July 2017,2018, Nicor Gas agreed to issue $400$300 million aggregate principal amount of first mortgage bonds in a private placement. Onplacement, $100 million of which was issued in August 10, 2017, Nicor2018 and $200 million of which was issued in
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


November 2018. The proceeds will be used for the repayment of short-term debt, capital expenditures, and other general corporate purposes.
Subsequent to September 30, 2018, Southern Company Gas issued $100Capital repaid at maturity $155 million aggregate principal amount of First Mortgage Bonds 3.03%3.50% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.B Senior Notes.
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 successor third quarter and year-to-date 2017.2018. 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 (C)(D) and (H)(I) to the Condensed Financial Statements herein for information relating to derivative instruments.
Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The following table illustratesFor the changeperiods presented below, the changes in the net fair value of Southern Company Gas' derivative instruments during all periods presented, and provides details of the net fair value of contracts outstandingwere as of the dates presented.follows:
 Successor  Predecessor
 Third Quarter Third Quarter Year-to-Date July 1, 2016 through September 30, 2016  January 1, 2016
through
June 30,
2016
 2017 2016 2017   Third Quarter 2018Third Quarter 2017 Year-to-Date 2018Year-to-Date 2017
 (in millions)  (in millions)(in millions)
Contracts outstanding at beginning of period,
assets (liabilities), net		 $51
 $(54) $12
 $(54)  $75
$(90)$51
 $(106)$12
Contracts realized or otherwise settled (6) (3) (22) (3)  (77)6
(6) 57
(22)
Current period changes(a)
 (16) —
 39
 —
  (82)(34)(16) (69)39
Contracts outstanding at the end of period,
assets (liabilities), net		 29
 (57) 29
 (57)  (84)$(118)$29

$(118)$29
Netting of cash collateral 76
 111
 76
 111
  120
189
76
 189
76
Cash collateral and net fair value of contracts
outstanding at end of period(b)
 $105
 $54
 $105
 $54
  $36
$71
$105

$71
$105
(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 instrumentscontracts outstanding includes premiumsexcludes premium and the intrinsic valuesvalue associated with weather derivatives of $5 million at September 30, 2018 and includes premium and the intrinsic value associated with weather derivatives of $13 million at September 30, 2017 and $7 million at September 30, 2016.2017.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 20172018 were as follows:
  Fair Value Measurements  Fair Value Measurements
  Successor – September 30, 2017  September 30, 2018
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)
$(35) $(10) $(20) $(5)$(145) $(8) $(106) $(31)
Level 2(b)
64
 12
 45
 7
27
 2
 25
 —
Fair value of contracts outstanding at end of period(c)
$29
 $2
 $25
 $2
$(118) $(6) $(81) $(31)
(a)Valued using NYMEX futures prices.
(b)Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
(c)Excludes cash collateral of $76$189 million as well as premium and associated intrinsic value associated with weather derivatives of $5 million at September 30, 2017.2018.

Table of Contents

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


INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
Note Page Number
A
Introduction
207208
B
Contingencies and Regulatory Matters
213218
C
Revenue from Contracts with Customers
238
D
Fair Value Measurements
236244
DE
Stockholders' Equity
240249
EF
Financing
242251
FG
Retirement Benefits
247255
GH
Income Taxes
253259
HI
Derivatives
255261
IJ
Acquisitions and Dispositions
270
J
Joint Ownership Agreements
273276
K
Variable Interest Entity and Equity Method Investments
280
L
Segment and Related Information
275282





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


Table of Contents

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)

(A)INTRODUCTION
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 20162017 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 September 30, 20172018 and 2016.2017. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of September 30, 2017 and December 31, 2016, are reflected within Southern Company's consolidated amounts in these accompanying notes herein. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" for additional information regarding the Merger.
Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of Southern Company Gas for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout Southern Company Gas' condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."
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.

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

Recently IssuedAdopted Accounting Standards
See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specificindustry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The new standard alsoadoption 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.
While the registrants expect most of their revenue to becustomers, which are included in the scope of Note (C).

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

ASC 606 they have not fully completed the evaluationprovided 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 all revenue arrangements. The majority ofproducts and services. In addition, contract assets related to certain fixed retail revenues at Georgia Power and Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not resultguidance in a significant shift from the current timing of revenue recognition for such transactions.
The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the registrants' financial statements. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants intend to use the modified retrospective method of adoption effective January 1, 2018. The registrants have also elected to utilize practical expedients which allow them to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are These reclassifications did not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on eitheraffect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on revenue recognized over time, resulting in a change in the registrants'timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the third 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 and Southern Company Gas' consolidated net income by $4 million for the three months ended September 30, 2018 and increased Southern Company's and Southern Company Gas' consolidated net income by $1 million for the nine months ended September 30, 2018.
The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements the registrants will continueof Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to evaluate the requirements, as well as any additional clarifyingpreviously recognized guidance that may be issued.is shown below.

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

 For the Three Months Ended
September 30, 2018		 For the Nine Months Ended
September 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$492
$497
$(5) $2,806
$2,805
$1
Other revenues199
198
1
 1,007
1,003
4
Other operations and maintenance1,404
1,387
17
 4,217
4,178
39
Operating income2,174
2,195
(21) 3,613
3,647
(34)
Other income (expense), net57
41
16
 195
160
35
Earnings (loss) before income taxes1,845
1,850
(5) 2,629
2,628
1
Income taxes (benefit)623
624
(1) 598
598
—
Consolidated net income (loss)1,222
1,226
(4) 2,031
2,030
1
Consolidated net income (loss) attributable to Southern Company1,164
1,168
(4) 1,948
1,947
1
        
Alabama Power       
Other revenues$68
$59
$9
 $199
$173
$26
Other operations and maintenance401
390
11
 1,191
1,159
32
Operating income561
563
(2) 1,313
1,319
(6)
Other income (expense), net9
7
2
 24
18
6
        
Georgia Power       
Other revenues$121
$97
$24
 $349
$287
$62
Other operations and maintenance460
437
23
 1,325
1,268
57
Operating income (loss)991
990
1
 1,032
1,027
5
Other income (expense), net30
31
(1) 104
109
(5)
        
Southern Company Gas       
Natural gas revenues$487
$492
$(5) $2,829
$2,828
$1
Operating income374
379
(5) 810
809
1
Earnings before income taxes362
367
(5) 769
768
1
Income taxes316
317
(1) 475
475
—
Net income (loss)46
50
(4) 294
293
1

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

 For the Nine Months Ended
September 30, 2018
Condensed Statements of Cash FlowsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Consolidated net income$2,031
$2,030
$1
Changes in certain current assets and liabilities:   
Receivables37
27
10
Other current assets(90)(80)(10)
Other current liabilities(67)(68)1
    
Georgia Power   
Changes in certain current assets and liabilities:   
Receivables$(205)$(242)$37
Other current assets(36)1
(37)
    
Southern Company Gas   
Net income$294
$293
$1
Changes in certain current assets and liabilities:   
Other current liabilities35
34
1
 At September 30, 2018
Condensed Balance SheetsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Unbilled revenues$738
$776
$(38)
Other accounts and notes receivable690
691
(1)
Other current assets232
193
39
Other current liabilities763
764
(1)
Retained earnings9,048
9,047
1
    
Georgia Power   
Unbilled revenues$245
$310
$(65)
Other accounts and notes receivable96
97
(1)
Other current assets91
25
66
    
Southern Company Gas   
Other current liabilities122
123
(1)
Accumulated deficit(273)(274)1
Other
On January 26, 2017,In 2016, the FASB issued ASU No. 2017-04,2016-18, Intangibles – Goodwill and OtherStatement of Cash Flows (Topic 350)230): Simplifying the Test for Goodwill ImpairmentRestricted Cash (ASU 2017-04)2016-18). ASU 2017-04 removes2016-18 eliminates the requirementneed to comparereflect transfers between cash and restricted cash in operating,

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

investing, and financing activities in the implied fair valuestatements of goodwill withcash flows. In addition, the carrying amountnet change in cash and cash equivalents during the period includes amounts generally described as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation.restricted cash or restricted cash equivalents. The registrants adopted ASU 2017-04 is2016-18 effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.2018 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 are evaluating the standard and expect to early adopt ASU 2017-04 effective January 1, 2018.in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.
OnIn March 10, 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

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

(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 statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations.The registrants adopted ASU 2017-07 will beeffective 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 in the income statement.is required. The requirement to limit capitalization ofto the service cost component of net periodic pension and postretirement benefit costs in assets will behas been applied on a prospective basis. ASU 2017-07 is effectivebasis from the date of adoption for annual periods beginning after December 15, 2017, including interim periods within those annual periods.all registrants. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to resultresulted in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact onthe three and nine months ended September 30, 2018 and 2017 for Southern Company's,Company, the traditional electric operating companies', orcompanies, and Southern Company Gas' financial statements.Gas.
OnIn August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements.. 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, and interim periods within those fiscal years, with early adoption permitted. The registrants are evaluating the standard and expect to early adoptadopted ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.
On February 14, 2018, the registrants'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.
Affiliate TransactionsAsset Retirement Obligations
PriorSee Note 1 to the completionfinancial statements of Southern Company Gas' acquisitionand the traditional electric operating companies under "Asset Retirement Obligations and Other Costs of its 50% equity interestRemoval" in SNG, SCS (as agentItem 8 of the Form 10-K for Alabama Power, Georgia Power,additional information regarding each company's AROs and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditionsEPA's Disposal of SNG's natural gas tariff and is subject to FERC regulation. For the nine months ended September 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $8 million, $77 million, $19 million, and $24 million, respectively. For the period subsequent to Southern Company Gas' investment in SNG through September 30, 2016, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $8 million, $2 million, and $4 million, respectively.
SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power and Southern PowerCoal Combustion Residuals from Southern Company Gas' subsidiaries were approximately $18 million and $94 million, respectively. For the period subsequent to Southern Company's acquisition of Southern Company Gas through September 30, 2016, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $7 million and $2 million, respectively.Electric Utilities final rule (CCR Rule).

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

As of September 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power were as follows:
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 Gulf
Power		 
Mississippi
Power
 (in millions)
Balance at December 31, 2017$4,824
 $1,709
 $2,638
 $142
 $174
Liabilities incurred2
 —
 —
 —
 —
Liabilities settled(160) (31) (82) (23) (22)
Accretion153
 72
 70
 3
 4
Cash flow revisions1,510
 1,451
 (32) 42
 21
Reclassification to held for sale(164) —
 —
 —
 —
Balance at September 30, 2018$6,165
 $3,201
 $2,594
 $164
 $177
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. Mississippi Power also recorded an increase of approximately $11 million to its AROs related to an ash pond at Plant Greene County, which is jointly-owned with Alabama Power. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including Plant Greene County. 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 the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
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 Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. 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.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's and Georgia Power's ARO liability. The ultimate outcome of these studies cannot be determined at this time.

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
At September 30, 2017The following table presents year-to-date changes in goodwill balances for Southern Company and December 31, 2016, goodwill was as follows:Southern Company Gas:
 Goodwill
 At September 30, 2017At December 31, 2016
 (in millions)
Southern Company$6,267
$6,251
Southern Power$2
$2
Southern Company Gas  
Gas distribution operations$4,702
$4,702
Gas marketing services1,265
1,265
Southern Company Gas total$5,967
$5,967
 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)
Dispositions(b)
(910) (668)(242)(910)
Balance at September 30, 2018$5,315
(c) 
$4,034
$981
$5,015
(a)
On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note (J) under "Southern Company Gas" for additional information.
(b)
Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) under "Southern Company Gas" 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.

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

Other intangible assets were as follows:
At September 30, 2017 At December 31, 2016At September 30, 2018 At December 31, 2017
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$288
$(70)$218
 $268
$(32)$236
Trade names159
(15)144
 158
(5)153
Customer relationships(*)
$223
$(87)$136
 $288
$(83)$205
Trade names(*)
70
(18)52
 159
(17)142
Storage and transportation contracts64
(27)37
 64
(2)62
64
(49)15
 64
(34)30
PPA fair value adjustments456
(41)415
 456
(22)434
456
(66)390
 456
(47)409
Other16
(3)13
 11
(1)10
11
(5)6
 17
(5)12
Total other intangible assets subject to amortization$983
$(156)$827

$957
$(62)$895
$824
$(225)$599

$984
$(186)$798
Other intangible assets not subject to amortization:      
Federal Communications Commission licenses$75
$—
$75
 $75
$—
$75
75
—
75
 75
—
75
Total other intangible assets$1,058
$(156)$902
 $1,032
$(62)$970
$899
$(225)$674
 $1,059
$(186)$873
      
Southern Power      
Other intangible assets subject to amortization:      
PPA fair value adjustments$456
$(41)$415
 $456
$(22)$434
$456
$(66)$390
 $456
$(47)$409
      
Southern Company Gas      
Other intangible assets subject to amortization:      
Gas marketing services   
Gas marketing services(*)
   
Customer relationships$221
$(65)$156
 $221
$(30)$191
$156
$(78)$78
 $221
$(77)$144
Trade names115
(8)107
 115
(2)113
26
(6)20
 115
(9)106
Wholesale gas services      
Storage and transportation contracts64
(27)37
 64
(2)62
64
(49)15
 64
(34)30
Total other intangible assets subject to amortization$400
$(100)$300
 $400
$(34)$366
$246
$(133)$113
 $400
$(120)$280
(*)
Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

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

Amortization associated with other intangible assets was as follows:
Three Months EndedNine Months EndedThree Months EndedNine Months Ended
September 30, 2017September 30, 2018
(in millions)(in millions)
Southern Company$29
$94
$21
$70
Southern Power$6
$19
$6
$19
Southern Company Gas$20
$66
$12
$42
Restricted Cash
See Note 12 to the financial statementsThe registrants adopted ASU 2016-18 as of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) underJanuary 1, 2018. See "Southern CompanyRecently Adopted Accounting Standards– Acquisition of PowerSecureOther" and " –Merger with Southern Company Gas"herein for additional information.
Property Damage ReserveAt December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both September 30, 2018 and December 31, 2017, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.
See Note 1The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the financialamounts shown in the condensed statements of Gulf Power under "Property Damage Reserve" in Item 8 ofcash flows for the Form 10-K for additional information.
Gulf Power's cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property is charged to Gulf Power's property damage reserve. In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), Gulf Power suspended further property damage reserve accruals effective April 2017. Gulf Power may make discretionary accruals and is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm eventsregistrants that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the property damage reserve to approximately $40 million. As ofhad restricted cash at September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 million. See Note (B) under "Regulatory Matters–Gulf Power– Retail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.2018 and/or December 31, 2017:
 Southern Company Southern Company Gas
 (in millions)
At September 30, 2018   
Cash and cash equivalents$1,847
 $56
Cash and cash equivalents classified as assets held for sale37
 —
Restricted cash:   
Other accounts and notes receivable6
 6
Total cash, cash equivalents, and restricted cash$1,891
(*) 
$62
(*)Total does not add due to rounding.
 Southern Company
Southern
Power
Southern Company Gas
 (in millions)
At December 31, 2017   
Cash and cash equivalents$2,130
$129
$73
Restricted cash:   
Other accounts and notes receivable5
—
5
Deferred charges and other assets12
11
—
Total cash, cash equivalents, and restricted cash$2,147
$140
$78
Natural Gas for SaleEnvironmental Remediation
Southern Company Gas' natural gas distribution utilities, withSubsequent to the exceptiondisposition of NicorElizabethtown Gas, carry natural gas inventory on a WACOG basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas had no inventory decrementis subject to environmental remediation liabilities associated with 40 former manufactured gas plant sites in four different states. Accrued environmental remediation costs decreased at September 30, 2017. The cost2018 primarily due to the disposition of natural gas, including inventory costs, is recovered from customers$85 million that related to Elizabethtown Gas.
See Note (B) under a purchased gas recovery mechanism adjusted for differences between actual costs"Environmental Matters–Environmental Remediation" to the Condensed Financial Statements herein and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lowerMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" 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 noin Item 7 and Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material LOCOM adjustment in any period presented.permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.

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

(B)CONTINGENCIES AND REGULATORY MATTERS
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the registrantsForm 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
Riders
On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds, via bill credits, began on July 1, 2018 related to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Base Rate Cases
Settled Base Rate Cases
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE 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."
On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected test year ending June 30, 2019 and a ROE of 9.80%. The new rates became effective November 1, 2018.
Other
The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On August 30, 2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits, for the related amounts deferred as a regulatory asset. The Virginia Commission is expected to rule on the filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas' annual base rate revenues would be reduced by $14 million. 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. The sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy did not impact the asset management agreement between wholesale gas services and Florida City Gas, which will remain in effect until its original maturity of March 31, 2019. 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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 in July 2018, infrastructure expenditures incurred in the first nine months of 2018 were as follows:
UtilityProgramYear-to-Date 2018
  (in millions)
Nicor GasInvesting in Illinois$267
Atlanta Gas LightGeorgia Rate Adjustment Mechanism (GRAM) infrastructure spending217
Virginia Natural GasSteps to Advance Virginia's Energy33
Total $517
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K for additional information.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas," and Note (H) to the Condensed Financial Statements herein for information relating toregarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Southern Company Gas is involved in various lawsuits, other contingencies,matters being litigated and regulatory matters.
General Litigation Matters
Each registrantmatters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. 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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiariesor 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 such registrant'sSouthern Company Gas' financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.
Southern Company Gas owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida, which was placed in service in October 2018. This facility is outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company Gas will adopt the new standard effective January 1, 2019.
Southern Company Gas has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company Gas expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company Gas expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company Gas also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Southern Company Gas is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Southern Company Gas has substantially completed its lease inventory and determined its most significant leases involve real estate and fleet vehicles. While Southern Company Gas has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company Gas' balance sheet each totaling approximately $90 million, with no material impact on Southern Company Gas' statement of income.
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 September 30, 2018. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2018, the amount of subsidiary retained earnings restricted to dividend totaled $786 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.
Net cash provided from operating activities totaled $736 million for the first nine months of 2018, a decrease of $410 million from the corresponding period in 2017. The decrease was primarily due to higher income tax payments due to the net taxable gains from the Southern Company Gas Dispositions, partially offset by increased volumes of natural gas sold during the first nine months of 2018 as a result of colder weather compared to the prior year. Net cash provided from investing activities totaled $1.4 billion for the first nine months of 2018 primarily due to proceeds from the Southern Company Gas Dispositions, partially offset by gross property additions primarily related to utility capital expenditures and pre-approved rider and infrastructure investments recovered through
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


replacement programs at gas distribution operations as well as capital contributed to equity method investments in pipelines. Net cash used for financing activities totaled $2.2 billion for the first nine months of 2018 primarily due to net repayments of commercial paper borrowings, the redemption of gas facility revenue bonds, and common stock dividend payments and return of capital to Southern Company, partially offset by proceeds from the issuance of first mortgage 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 nine months of 2018 include $2.8 billion and $404 million in total assets and liabilities sold, respectively, associated with the Southern Company Gas Dispositions as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas," a decrease of $109 million in natural gas for sale due to the use of stored natural gas, and a $1.4 billion decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $63 million in accounts payable as well as $109 million and $25 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and an increase of $714 million in total property, plant, and equipment primarily due to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements and contractual obligations. Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $350 million will be required through September 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, external securities issuances, borrowings from financial institutions, and borrowings and equity contributions from Southern Company. 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.
Southern Company Gas' current liabilities exceeded current assets by $469 million primarily as a result of $515 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 intends to utilize operating cash flows, external securities issuances, borrowings from financial institutions, borrowings and equity contributions from Southern Company, and the proceeds from its dispositions to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


At September 30, 2018, Southern Company Gas had $56 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 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 6 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to Southern Company Gas.
Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
 
Short-Term Debt at
September 30, 2018
 
Short-Term Debt During the Period(*)
 Amount
Outstanding		 Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
Commercial paper:(in millions)   (in millions)   (in millions)
Southern Company Gas Capital$—
 —% $18
 2.4% $573
Nicor Gas136
 2.4% 67
 2.3% 154
Short-term loans:         
Southern Company Gas—
 —% 12
 2.8% 276
Total$136
 2.4% $97
 2.3%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.
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, prior to its sale, 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


$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 September 30, 2018 was approximately $10 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.
On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas).
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.
Financing Activities
The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of September 30, 2018, the non-principal components totaled $469 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 20, 2017, a purported securities class action complaint was filed against4, 2018, Southern Company certainGas 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.
Prior to its officers, and certain former Mississippi Power officerssale, in the U.S. District Courtsecond 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. In July 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 repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.
In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


November 2018. The proceeds will be used for the Northern Districtrepayment 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, 2012short-term debt, capital expenditures, and October 29, 2013. The complaint alleges thatother general corporate purposes.
Subsequent to September 30, 2018, Southern Company certainGas Capital repaid at maturity $155 million aggregate principal amount of its officers,3.50% Series B Senior Notes.
In addition to any financings that may be necessary to meet capital requirements and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper IGCC 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. On June 12, 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. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendantscontractual obligations, Southern Company certain of its directors, certain of its officers,Gas plans to continue, when economically feasible, a program to retire higher-cost securities and certain former Mississippi Power officers. The complaint alleges thatreplace these obligations with lower-cost capital if market conditions permit.
Market Price Risk
Other than the defendants causeditems discussed below, there were no material changes to Southern Company to make false or misleading statements regardingGas' disclosures about market price risk during the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalfthird quarter 2018. For an in-depth discussion of Southern Company unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov 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. Each 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 IGCC. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalfGas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company unspecified actual damagesGas in Item 7 of the Form 10-K. Also see Notes (D) and (I) to the Condensed Financial Statements herein for information relating to derivative instruments.
Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:
 Third Quarter 2018Third Quarter 2017 Year-to-Date 2018Year-to-Date 2017
 (in millions)
Contracts outstanding at beginning of period, assets (liabilities), net$(90)$51
 $(106)$12
Contracts realized or otherwise settled6
(6) 57
(22)
Current period changes(a)
(34)(16) (69)39
Contracts outstanding at the end of period, assets (liabilities), net$(118)$29

$(118)$29
Netting of cash collateral189
76
 189
76
Cash collateral and net fair value of contracts outstanding at end of period(b)
$71
$105

$71
$105
(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 $5 million at September 30, 2018 and includes premium and the intrinsic value associated with weather derivatives of $13 million at September 30, 2017.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2018 were as follows:
   Fair Value Measurements
   September 30, 2018
 Total
Fair Value		 Maturity
  Year 1  Years 2 & 3 Years 4 and thereafter
 (in millions)
Level 1(a)
$(145) $(8) $(106) $(31)
Level 2(b)
27
 2
 25
 —
Fair value of contracts outstanding at end of period(c)
$(118) $(6) $(81) $(31)
(a)Valued using NYMEX futures prices.
(b)Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
(c)Excludes cash collateral of $189 million as well as premium and associated intrinsic value associated with weather derivatives of $5 million at September 30, 2018.

Table of Contents

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
NotePage Number
A
Introduction
208
B
Contingencies and Regulatory Matters
218
C
Revenue from Contracts with Customers
238
D
Fair Value Measurements
244
E
Stockholders' Equity
249
F
Financing
251
G
Retirement Benefits
255
H
Income Taxes
259
I
Derivatives
261
J
Acquisitions and Dispositions
276
K
Variable Interest Entity and Equity Method Investments
280
L
Segment and Related Information
282





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


Table of Contents

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)

(A)INTRODUCTION
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2017 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2018 and 2017. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
Recently Adopted Accounting Standards
See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).

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 disgorgementother operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of profitsproducts and on its behalf, attorneys' feesservices. In addition, contract assets related to certain fixed retail revenues at Georgia Power and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidatedunregulated 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 revenue recognized over time, resulting in a change in the U.S. District Courttiming of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the third 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 and Southern Company Gas' consolidated net income by $4 million for the Northern District of Georgiathree months ended September 30, 2018 and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
increased Southern Company's and Southern Company believes these legal challenges have no merit; however, an adverse outcome in anyGas' consolidated net income by $1 million for the nine months ended September 30, 2018.
The specific impacts 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.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of municipal franchise fees (all of which are remittedapplying ASC 606 to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. Georgia Power filed a petition for writ of certiorarirevenues from contracts with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is not expected until 2018. Georgia Power believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a liencustomers on the Roserock facility for the same amount. The amounts withheld are included in other accounts and notes payable and other current liabilities on Southern Company's consolidated balance sheets and other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. 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 Gas and Nicor Energy Services Company, wholly-owned subsidiariesfinancial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purportedcompared to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes theypreviously recognized guidance is shown below.

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

purported
 For the Three Months Ended
September 30, 2018		 For the Nine Months Ended
September 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$492
$497
$(5) $2,806
$2,805
$1
Other revenues199
198
1
 1,007
1,003
4
Other operations and maintenance1,404
1,387
17
 4,217
4,178
39
Operating income2,174
2,195
(21) 3,613
3,647
(34)
Other income (expense), net57
41
16
 195
160
35
Earnings (loss) before income taxes1,845
1,850
(5) 2,629
2,628
1
Income taxes (benefit)623
624
(1) 598
598
—
Consolidated net income (loss)1,222
1,226
(4) 2,031
2,030
1
Consolidated net income (loss) attributable to Southern Company1,164
1,168
(4) 1,948
1,947
1
        
Alabama Power       
Other revenues$68
$59
$9
 $199
$173
$26
Other operations and maintenance401
390
11
 1,191
1,159
32
Operating income561
563
(2) 1,313
1,319
(6)
Other income (expense), net9
7
2
 24
18
6
        
Georgia Power       
Other revenues$121
$97
$24
 $349
$287
$62
Other operations and maintenance460
437
23
 1,325
1,268
57
Operating income (loss)991
990
1
 1,032
1,027
5
Other income (expense), net30
31
(1) 104
109
(5)
        
Southern Company Gas       
Natural gas revenues$487
$492
$(5) $2,829
$2,828
$1
Operating income374
379
(5) 810
809
1
Earnings before income taxes362
367
(5) 769
768
1
Income taxes316
317
(1) 475
475
—
Net income (loss)46
50
(4) 294
293
1

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

 For the Nine Months Ended
September 30, 2018
Condensed Statements of Cash FlowsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Consolidated net income$2,031
$2,030
$1
Changes in certain current assets and liabilities:   
Receivables37
27
10
Other current assets(90)(80)(10)
Other current liabilities(67)(68)1
    
Georgia Power   
Changes in certain current assets and liabilities:   
Receivables$(205)$(242)$37
Other current assets(36)1
(37)
    
Southern Company Gas   
Net income$294
$293
$1
Changes in certain current assets and liabilities:   
Other current liabilities35
34
1
 At September 30, 2018
Condensed Balance SheetsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Unbilled revenues$738
$776
$(38)
Other accounts and notes receivable690
691
(1)
Other current assets232
193
39
Other current liabilities763
764
(1)
Retained earnings9,048
9,047
1
    
Georgia Power   
Unbilled revenues$245
$310
$(65)
Other accounts and notes receivable96
97
(1)
Other current assets91
25
66
    
Southern Company Gas   
Other current liabilities122
123
(1)
Accumulated deficit(273)(274)1
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 represent, actualreflect transfers between cash and punitive damages, interest, costs, attorney fees,restricted cash in operating,

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

investing, and injunctive relief. On February 8, 2017,financing activities in the judge deniedstatements of cash flows. In addition, the plaintiffs' motion for class certificationnet change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas' motionGas 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 summary judgment. OnSouthern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.
In March 7, 2017, the parties reached a settlement, which was finalizedFASB 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 on April 3, 2017. The settlement did not have aJanuary 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 nine months ended September 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 September 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power were as follows:
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 Gulf
Power		 
Mississippi
Power
 (in millions)
Balance at December 31, 2017$4,824
 $1,709
 $2,638
 $142
 $174
Liabilities incurred2
 —
 —
 —
 —
Liabilities settled(160) (31) (82) (23) (22)
Accretion153
 72
 70
 3
 4
Cash flow revisions1,510
 1,451
 (32) 42
 21
Reclassification to held for sale(164) —
 —
 —
 —
Balance at September 30, 2018$6,165
 $3,201
 $2,594
 $164
 $177
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. Mississippi Power also recorded an increase of approximately $11 million to its AROs related to an ash pond at Plant Greene County, which is jointly-owned with Alabama Power. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including Plant Greene County. 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 the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
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 Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. Absent continued recovery of ARO costs through regulated rates, Southern Company's orand 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.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's and Georgia Power's ARO liability. The ultimate outcome of these studies cannot be determined at this time.

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 Gas'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.statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Environmental MattersIn 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 Company and Southern Company Gas:
 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)
Dispositions(b)
(910) (668)(242)(910)
Balance at September 30, 2018$5,315
(c) 
$4,034
$981
$5,015
(a)
On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note (J) under "Southern Company Gas" for additional information.
(b)
Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) under "Southern Company Gas" 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.

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

Other intangible assets were as follows:
 At September 30, 2018 At December 31, 2017
 Gross Carrying AmountAccumulated Amortization
Other
Intangible Assets, Net
 Gross Carrying AmountAccumulated AmortizationOther
Intangible Assets, Net
 (in millions) (in millions)
Southern Company       
Other intangible assets subject to amortization:       
Customer relationships(*)
$223
$(87)$136
 $288
$(83)$205
Trade names(*)
70
(18)52
 159
(17)142
Storage and transportation contracts64
(49)15
 64
(34)30
PPA fair value adjustments456
(66)390
 456
(47)409
Other11
(5)6
 17
(5)12
Total other intangible assets subject to amortization$824
$(225)$599

$984
$(186)$798
Other intangible assets not subject to amortization:       
Federal Communications Commission licenses75
—
75
 75
—
75
Total other intangible assets$899
$(225)$674
 $1,059
$(186)$873
        
Southern Power       
Other intangible assets subject to amortization:       
PPA fair value adjustments$456
$(66)$390
 $456
$(47)$409
        
Southern Company Gas       
Other intangible assets subject to amortization:       
Gas marketing services(*)
       
Customer relationships$156
$(78)$78
 $221
$(77)$144
Trade names26
(6)20
 115
(9)106
Wholesale gas services       
Storage and transportation contracts64
(49)15
 64
(34)30
Total other intangible assets subject to amortization$246
$(133)$113
 $400
$(120)$280
(*)
Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

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

Amortization associated with other intangible assets was as follows:
 Three Months EndedNine Months Ended
 September 30, 2018
 (in millions)
Southern Company$21
$70
Southern Power$6
$19
Southern Company Gas$12
$42
Restricted Cash
The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.
At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both September 30, 2018 and December 31, 2017, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at September 30, 2018 and/or December 31, 2017:
 Southern Company Southern Company Gas
 (in millions)
At September 30, 2018   
Cash and cash equivalents$1,847
 $56
Cash and cash equivalents classified as assets held for sale37
 —
Restricted cash:   
Other accounts and notes receivable6
 6
Total cash, cash equivalents, and restricted cash$1,891
(*) 
$62
(*)Total does not add due to rounding.
 Southern Company
Southern
Power
Southern Company Gas
 (in millions)
At December 31, 2017   
Cash and cash equivalents$2,130
$129
$73
Restricted cash:   
Other accounts and notes receivable5
—
5
Deferred charges and other assets12
11
—
Total cash, cash equivalents, and restricted cash$2,147
$140
$78
Environmental Remediation
TheSubsequent to the disposition of Elizabethtown Gas, Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $26 million and $17 million as of September 30, 2017 and December 31, 2016, 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 $53 million and $44 million as of September 30, 2017 and December 31, 2016, 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 projectsGas is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
Southern Company Gas' environmental remediation liability was $399 million and $426 million as of September 30, 2017 and December 31, 2016, respectively, based on the estimated cost of environmental investigation and remediationliabilities associated with known current and40 former manufactured gas plant operating sites. Thesesites in four different states. Accrued environmental remediation expenditures are recoverable from customers through rate mechanisms approved bycosts decreased at September 30, 2018 primarily due to the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs.
The final outcome of these matters cannot be determined at this time. However, the final disposition of these matters is not expected$85 million that related to have a material impact onElizabethtown Gas.
See Note (B) under "Environmental Matters–Environmental Remediation" to the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.
Natural Gas Storage
A wholly-owned subsidiaryCondensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas ownsin Item 7 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 (LDNR). 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 September 30, 2017, 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 the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage

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

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.
Nuclear Fuel Disposal Costs
See Note 3 to the financial statements of Southern Company Alabama Power, and Georgia PowerGas under "Nuclear Fuel Disposal Costs" in Item 8 of the Form 10-K for additional information regarding legal remedies pursued by Alabama Power and Georgia Power against the U.S. government for its partial breach of contract relating to the disposal of spent nuclear fuel and high level radioactive waste generated at each company's nuclear plants.
On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley, Plant Hatch, and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of September 30, 2017 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC"Environmental Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.
In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.
See "Integrated Coal Gasification Combined Cycle" herein for additional information.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2017 and December 31, 2016.
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.

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

Market-Based Rate AuthorityFERC Matters
See Note 3 to the financial statementsMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company and Mississippi Power under "FERC Matters – Market-Based Rate Authority" and Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Southern Power under "FERC Matters"Gas in Item 87 of the Form 10-K for additional information regarding the traditional electric operating companies'information.
The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 2018 and Southern Power's market power proceeding and amendmentcontinues to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordancework with the February 2, 2017 order, orappropriate agencies to provide a mitigation planobtain the necessary permits. The PennEast Pipeline continues to further address market power concerns. The traditional electric operating companieswork with state and Southern Power expectfederal agencies to make a filing withinobtain the specified 60 days respondingrequired permits to the FERC's order.
begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama PowerGas 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 ItemSeptember 30,
2017		December 31,
2016


(in millions)
Rate CNP ComplianceDeferred over recovered regulatory clause revenues$9
$—
Rate CNP Compliance(*)
Deferred under recovered regulatory clause revenues—
9
Rate CNP PPADeferred under recovered regulatory clause revenues17
142
Retail Energy Cost Recovery(*)
Other regulatory liabilities, current—
76
Natural Disaster ReserveOther regulatory liabilities, deferred51
69
(*)In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance for Rate CNP Compliance and $11 million of its under recovered balance for Retail Energy Cost Recovery to a deferred regulatory asset account.
Georgia Power
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.

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

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – 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.
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
As of September 30, 2017, Georgia Power's under recovered fuel balance totaled $100 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's condensed balance sheets. As of December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other current liabilities on Southern Company's and Georgia Power's condensed balance sheets.
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.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

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

Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, and the Contractor Settlement Agreement.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.
The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee

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

Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a 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 at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of

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

the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement, 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 connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the term sheet, 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 or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC 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 by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.
The term sheet also confirms 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.
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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia

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

Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.
In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.
The ultimate outcome of these matters cannot be determined at this time.
Revised Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
 (in billions)
Estimated cost to complete$4.2
CWIP as of September 30, 20174.6
Guarantee Obligations(1.7)
Estimated capital costs$7.1
Vogtle Cost Settlement Agreement Revised Forecast(5.7)
Estimated net additional capital costs$1.4
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.

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

Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:
 Cancellation Cost Estimate
 (in billions)
CWIP as of September 30, 2017$4.6
Financing costs collected, net of tax1.5
Cancellation costs(*)
0.4
Guarantee Obligations(1.7)
Estimated net cancellation cost$4.8
(*)The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.
The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of September 30, 2017, 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. On September 28, 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. 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. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings"Matters" in Item 8 of the Form 10-K and Note (E)(B) to the Condensed Financial Statements under "DOE Loan Guarantee BorrowingsRegulatory Matters – Southern Company Gas" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
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 while construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise while construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

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

While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-Kherein for additional information regarding Gulf Power's rates and charges for service to retail customers.
Retail Base Rate Cases
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.Gas' regulatory matters.
In 2013, the Florida PSC approved a settlement agreement that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. Through June 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.Riders
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1,19, 2018, and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.

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

Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:
Regulatory ClauseBalance Sheet Line ItemSeptember 30,
2017		December 31,
2016


(in millions)
Fuel Cost RecoveryUnder recovered regulatory clause revenues$13
$—
Fuel Cost RecoveryOther regulatory liabilities, current—
15
Purchased Power Capacity RecoveryUnder recovered regulatory clause revenues1
—
Environmental Cost RecoveryOther regulatory liabilities, current1
—
Environmental Cost RecoveryUnder recovered regulatory clause revenues—
13
Energy Conservation Cost RecoveryUnder recovered regulatory clause revenues1
4
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On October 25, 2017, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.
Mississippi Power
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.
On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.
On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.
Environmental Compliance Overview Plan
On May 4, 2017, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel Units 1

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

and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's retail fuel cost recovery.
At September 30, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $2 million compared to $37 million at December 31, 2016.
Ad Valorem Tax Adjustment
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.
On July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.
Southern Company Gas
Riders
Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017.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, via bill credits, began on July 1, 2018 related to the invested capital tax imposed onimpacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas through an annual true-up and reconciliation mechanism based on amountsGas' approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Base Rate Cases
Settled Base Rate Cases
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE 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."
On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected test year ending June 30, 2019 and a ROE of 9.80%. The new rates became effective November 1, 2018.
Other
The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On August 30, 2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits, for the related amounts deferred as a regulatory asset. The Virginia Commission is expected to rule on the filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas' annual base rate revenues would be reduced by $14 million. 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. The sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy did not impact the asset management agreement between wholesale gas services and Florida City Gas, which will remain in effect until its original maturity of March 31, 2019. 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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 in July 2018, infrastructure expenditures incurred in the first nine months of 2018 were as follows:
UtilityProgramYear-to-Date 2018
  (in millions)
Nicor GasInvesting in Illinois$267
Atlanta Gas LightGeorgia Rate Adjustment Mechanism (GRAM) infrastructure spending217
Virginia Natural GasSteps to Advance Virginia's Energy33
Total $517
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K for additional information.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.
Southern Company Gas owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida, which was placed in service in October 2018. This facility is outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


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) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.
In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company Gas will adopt the new standard effective January 1, 2019.
Southern Company Gas has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company Gas expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company Gas expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company Gas also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.
Southern Company Gas is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Southern Company Gas has substantially completed its lease inventory and determined its most significant leases involve real estate and fleet vehicles. While Southern Company Gas has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company Gas' balance sheet each totaling approximately $90 million, with no material impact on Southern Company Gas' statement of income.
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 September 30, 2018. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2018, the amount of subsidiary retained earnings restricted to dividend totaled $786 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.
Net cash provided from operating activities totaled $736 million for the first nine months of 2018, a decrease of $410 million from the corresponding period in 2017. The decrease was primarily due to higher income tax payments due to the net taxable gains from the Southern Company Gas Dispositions, partially offset by increased volumes of natural gas sold during the first nine months of 2018 as a result of colder weather compared to the prior year. Net cash provided from investing activities totaled $1.4 billion for the first nine months of 2018 primarily due to proceeds from the Southern Company Gas Dispositions, partially offset by gross property additions primarily related to utility capital expenditures and pre-approved rider and infrastructure investments recovered through
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


replacement programs at gas distribution operations as well as capital contributed to equity method investments in pipelines. Net cash used for financing activities totaled $2.2 billion for the first nine months of 2018 primarily due to net repayments of commercial paper borrowings, the redemption of gas facility revenue bonds, and common stock dividend payments and return of capital to Southern Company, partially offset by proceeds from the issuance of first mortgage 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 nine months of 2018 include $2.8 billion and $404 million in total assets and liabilities sold, respectively, associated with the Southern Company Gas Dispositions as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas," a decrease of $109 million in natural gas for sale due to the use of stored natural gas, and a $1.4 billion decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $63 million in accounts payable as well as $109 million and $25 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and an increase of $714 million in total property, plant, and equipment primarily due to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements and contractual obligations. Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $350 million will be required through September 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, external securities issuances, borrowings from financial institutions, and borrowings and equity contributions from Southern Company. 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.
Southern Company Gas' current liabilities exceeded current assets by $469 million primarily as a result of $515 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 intends to utilize operating cash flows, external securities issuances, borrowings from financial institutions, borrowings and equity contributions from Southern Company, and the proceeds from its dispositions to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


At September 30, 2018, Southern Company Gas had $56 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 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 6 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to Southern Company Gas.
Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
 
Short-Term Debt at
September 30, 2018
 
Short-Term Debt During the Period(*)
 Amount
Outstanding		 Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
Commercial paper:(in millions)   (in millions)   (in millions)
Southern Company Gas Capital$—
 —% $18
 2.4% $573
Nicor Gas136
 2.4% 67
 2.3% 154
Short-term loans:         
Southern Company Gas—
 —% 12
 2.8% 276
Total$136
 2.4% $97
 2.3%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.
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, prior to its sale, 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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


$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 September 30, 2018 was approximately $10 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.
On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas).
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Base Rate Cases"Southern Company Gas" herein for additional information.
Financing Activities
The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of September 30, 2018, the non-principal components totaled $469 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.
Prior to its sale, 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. In July 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 repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.
In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


November 2018. The proceeds will be used for the repayment of short-term debt, capital expenditures, and other general corporate purposes.
Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.
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 third quarter 2018. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also see Notes (D) and (I) to the Condensed Financial Statements herein for information relating to derivative instruments.
Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:
 Third Quarter 2018Third Quarter 2017 Year-to-Date 2018Year-to-Date 2017
 (in millions)
Contracts outstanding at beginning of period, assets (liabilities), net$(90)$51
 $(106)$12
Contracts realized or otherwise settled6
(6) 57
(22)
Current period changes(a)
(34)(16) (69)39
Contracts outstanding at the end of period, assets (liabilities), net$(118)$29

$(118)$29
Netting of cash collateral189
76
 189
76
Cash collateral and net fair value of contracts outstanding at end of period(b)
$71
$105

$71
$105
(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 $5 million at September 30, 2018 and includes premium and the intrinsic value associated with weather derivatives of $13 million at September 30, 2017.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2018 were as follows:
   Fair Value Measurements
   September 30, 2018
 Total
Fair Value		 Maturity
  Year 1  Years 2 & 3 Years 4 and thereafter
 (in millions)
Level 1(a)
$(145) $(8) $(106) $(31)
Level 2(b)
27
 2
 25
 —
Fair value of contracts outstanding at end of period(c)
$(118) $(6) $(81) $(31)
(a)Valued using NYMEX futures prices.
(b)Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
(c)Excludes cash collateral of $189 million as well as premium and associated intrinsic value associated with weather derivatives of $5 million at September 30, 2018.

Table of Contents

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
NotePage Number
A
Introduction
208
B
Contingencies and Regulatory Matters
218
C
Revenue from Contracts with Customers
238
D
Fair Value Measurements
244
E
Stockholders' Equity
249
F
Financing
251
G
Retirement Benefits
255
H
Income Taxes
259
I
Derivatives
261
J
Acquisitions and Dispositions
276
K
Variable Interest Entity and Equity Method Investments
280
L
Segment and Related Information
282





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


Table of Contents

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)

(A)INTRODUCTION
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2017 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2018 and 2017. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
Recently Adopted Accounting Standards
See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.
Settled Base Rate CasesRevenue
On February 21, 2017,In 2014, the Georgia PSC approvedFASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the Georgia Rate Adjustment Mechanism (GRAM)existing accounting standard and industry-specific guidance for revenue recognition with a $20 million increasefive-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in annual base rate revenues for Atlanta Gas Light, effective Marcheffect as of January 1, 2017. GRAM adjusts base rates annually, up or down, based2018. 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 approved ROEreported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will berelated cash flows arising from contracts with customers, which are included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, aNote (C).

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

new tariffASC 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 certain fixed retail revenues at Georgia Power and 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 revenue recognized over time, 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 third 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 and Southern Company Gas' consolidated net income by $4 million for the three months ended September 30, 2018 and increased Southern Company's and Southern Company Gas' consolidated net income by $1 million for the nine months ended September 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
September 30, 2018		 For the Nine Months Ended
September 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$492
$497
$(5) $2,806
$2,805
$1
Other revenues199
198
1
 1,007
1,003
4
Other operations and maintenance1,404
1,387
17
 4,217
4,178
39
Operating income2,174
2,195
(21) 3,613
3,647
(34)
Other income (expense), net57
41
16
 195
160
35
Earnings (loss) before income taxes1,845
1,850
(5) 2,629
2,628
1
Income taxes (benefit)623
624
(1) 598
598
—
Consolidated net income (loss)1,222
1,226
(4) 2,031
2,030
1
Consolidated net income (loss) attributable to Southern Company1,164
1,168
(4) 1,948
1,947
1
        
Alabama Power       
Other revenues$68
$59
$9
 $199
$173
$26
Other operations and maintenance401
390
11
 1,191
1,159
32
Operating income561
563
(2) 1,313
1,319
(6)
Other income (expense), net9
7
2
 24
18
6
        
Georgia Power       
Other revenues$121
$97
$24
 $349
$287
$62
Other operations and maintenance460
437
23
 1,325
1,268
57
Operating income (loss)991
990
1
 1,032
1,027
5
Other income (expense), net30
31
(1) 104
109
(5)
        
Southern Company Gas       
Natural gas revenues$487
$492
$(5) $2,829
$2,828
$1
Operating income374
379
(5) 810
809
1
Earnings before income taxes362
367
(5) 769
768
1
Income taxes316
317
(1) 475
475
—
Net income (loss)46
50
(4) 294
293
1

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

 For the Nine Months Ended
September 30, 2018
Condensed Statements of Cash FlowsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Consolidated net income$2,031
$2,030
$1
Changes in certain current assets and liabilities:   
Receivables37
27
10
Other current assets(90)(80)(10)
Other current liabilities(67)(68)1
    
Georgia Power   
Changes in certain current assets and liabilities:   
Receivables$(205)$(242)$37
Other current assets(36)1
(37)
    
Southern Company Gas   
Net income$294
$293
$1
Changes in certain current assets and liabilities:   
Other current liabilities35
34
1
 At September 30, 2018
Condensed Balance SheetsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Unbilled revenues$738
$776
$(38)
Other accounts and notes receivable690
691
(1)
Other current assets232
193
39
Other current liabilities763
764
(1)
Retained earnings9,048
9,047
1
    
Georgia Power   
Unbilled revenues$245
$310
$(65)
Other accounts and notes receivable96
97
(1)
Other current assets91
25
66
    
Southern Company Gas   
Other current liabilities122
123
(1)
Accumulated deficit(273)(274)1
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,

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

investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was created,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 October 10,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 nine months ended September 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 September 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power were as follows:
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 Gulf
Power		 
Mississippi
Power
 (in millions)
Balance at December 31, 2017$4,824
 $1,709
 $2,638
 $142
 $174
Liabilities incurred2
 —
 —
 —
 —
Liabilities settled(160) (31) (82) (23) (22)
Accretion153
 72
 70
 3
 4
Cash flow revisions1,510
 1,451
 (32) 42
 21
Reclassification to held for sale(164) —
 —
 —
 —
Balance at September 30, 2018$6,165
 $3,201
 $2,594
 $164
 $177
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. Mississippi Power also recorded an increase of approximately $11 million to its AROs related to an ash pond at Plant Greene County, which is jointly-owned with Alabama Power. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including Plant Greene County. 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 the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.
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 Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.
The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. 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.
Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's and Georgia Power's ARO liability. The ultimate outcome of these studies cannot be determined at this time.

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 $15 million annually for Atlanta Gas Lightsite specific estimates of the decommissioning costs and related projections of funds in the external trust to committhe Alabama PSC and, if necessary, would seek the Alabama PSC's approval to strategic economic development projects.
Beginningaddress any changes in a manner consistent with the next rateNRC 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 Company and Southern Company Gas:
 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)
Dispositions(b)
(910) (668)(242)(910)
Balance at September 30, 2018$5,315
(c) 
$4,034
$981
$5,015
(a)
On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note (J) under "Southern Company Gas" for additional information.
(b)
Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) under "Southern Company Gas" 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.

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

Other intangible assets were as follows:
 At September 30, 2018 At December 31, 2017
 Gross Carrying AmountAccumulated Amortization
Other
Intangible Assets, Net
 Gross Carrying AmountAccumulated AmortizationOther
Intangible Assets, Net
 (in millions) (in millions)
Southern Company       
Other intangible assets subject to amortization:       
Customer relationships(*)
$223
$(87)$136
 $288
$(83)$205
Trade names(*)
70
(18)52
 159
(17)142
Storage and transportation contracts64
(49)15
 64
(34)30
PPA fair value adjustments456
(66)390
 456
(47)409
Other11
(5)6
 17
(5)12
Total other intangible assets subject to amortization$824
$(225)$599

$984
$(186)$798
Other intangible assets not subject to amortization:       
Federal Communications Commission licenses75
—
75
 75
—
75
Total other intangible assets$899
$(225)$674
 $1,059
$(186)$873
        
Southern Power       
Other intangible assets subject to amortization:       
PPA fair value adjustments$456
$(66)$390
 $456
$(47)$409
        
Southern Company Gas       
Other intangible assets subject to amortization:       
Gas marketing services(*)
       
Customer relationships$156
$(78)$78
 $221
$(77)$144
Trade names26
(6)20
 115
(9)106
Wholesale gas services       
Storage and transportation contracts64
(49)15
 64
(34)30
Total other intangible assets subject to amortization$246
$(133)$113
 $400
$(120)$280
(*)
Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

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

Amortization associated with other intangible assets was as follows:
 Three Months EndedNine Months Ended
 September 30, 2018
 (in millions)
Southern Company$21
$70
Southern Power$6
$19
Southern Company Gas$12
$42
Restricted Cash
The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.
At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both September 30, 2018 and December 31, 2017, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at September 30, 2018 and/or December 31, 2017:
 Southern Company Southern Company Gas
 (in millions)
At September 30, 2018   
Cash and cash equivalents$1,847
 $56
Cash and cash equivalents classified as assets held for sale37
 —
Restricted cash:   
Other accounts and notes receivable6
 6
Total cash, cash equivalents, and restricted cash$1,891
(*) 
$62
(*)Total does not add due to rounding.
 Southern Company
Southern
Power
Southern Company Gas
 (in millions)
At December 31, 2017   
Cash and cash equivalents$2,130
$129
$73
Restricted cash:   
Other accounts and notes receivable5
—
5
Deferred charges and other assets12
11
—
Total cash, cash equivalents, and restricted cash$2,147
$140
$78
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost.

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

Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas had no inventory decrement at September 30, 2018. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.
Hypothetical Liquidation at Book Value
Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the end of the period compared to the beginning of the period.
(B)CONTINGENCIES AND REGULATORY MATTERS
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Southern Company
In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September

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

2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. On August 10, 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.
In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On May 4, 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 orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in August 2017. On June 18, 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. On August 27, 2018,

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

Georgia Power filed a motion to stay the case and requested the trial court refer the case to the Georgia PSC for a declaratory ruling. Georgia Power believes the plaintiffs' claims have no merit and will continue to vigorously defend itself in this matter. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether any class will ultimately be certified; the scope of such a class, if certified; and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.
Mississippi Power
In 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's or Mississippi Power's financial statements.
On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. Southern Company and Mississippi Power believe this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in this matter, the ultimate outcome of which cannot be determined at this time.
On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Southern Company's and Mississippi Power's earnings for the nine months ended September 30, 2018.
Southern Power
Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in November 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In May 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail storm and McCarthy's installation practices. On June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. In addition to the State Court lawsuit, lawsuits were filed between Roserock

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

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 included in other operations and maintenance expenses for the nine months ended September 30, 2018.
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 and Georgia have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $25 million and $22 million as of September 30, 2018 and December 31, 2017, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $48 million and $52 million as of September 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 September 30, 2018, Southern Company Gas' environmental remediation liability was $294 million based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. At December 31, 2017, Southern Company Gas' total environmental remediation liability was $388 million, of which $85 million related to Elizabethtown Gas, which was sold on July 1, 2018. 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" for information regarding Southern Company Gas' sale of Elizabethtown Gas.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.

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

FERC Matters
Market-Based Rate Authority
See Note 3 to the financial statements of Southern Company, the traditional electric operating companies, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating 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 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. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's or the traditional electric operating companies' results of operations. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $7 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2018 and December 31, 2017.
Cooperative Energy Power Supply Agreement
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.
On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.
Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional

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

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 ItemSeptember 30,
2018		December 31,
2017
  (in millions)
Rate CNP ComplianceDeferred under recovered regulatory clause revenues$—
$17
 Under recovered regulatory clause revenues7
—
Rate CNP PPADeferred under recovered regulatory clause revenues30
12
Retail Energy Cost RecoveryDeferred under recovered regulatory clause revenues58
25
 Under recovered regulatory clause revenues41
—
Natural Disaster ReserveOther regulatory liabilities, deferred24
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 September 30, 2018, Alabama Power's equity ratio was approximately 47%.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 Atlanta Gas Light's recoveryand are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the previously unrecovered Pipeline Replacement Programallowed 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 2014,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 has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 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. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.

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

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 September 30, 2018, Alabama Power had applied the full $30 million 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 four-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 mitigationproposed 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. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 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

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

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. At September 30, 2018, Georgia Power's related regulatory liability balance totaled $655 million. 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. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. 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 September 30, 2018 and December 31, 2017, Georgia Power's under recovered fuel balance totaled $105 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. On August 16, 2018, the Georgia PSC approved the deferral of Georgia Power's next fuel case to no later than March 16, 2020, with rates to be effective June 1, 2020. 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.
Storm Damage Recovery
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was $311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately $125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.
Gulf Power
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.
Storm Damage Cost Recovery
See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for information on how Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property.

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

On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the Pipeline Replacement Program that were not previouslyproperty damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.
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 provided 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 September 30, 2018, approximately $53 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. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

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

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 ItemSeptember 30,
2018		December 31,
2017
  (in millions)
Fuel Cost RecoveryUnder recovered regulatory clause revenues$—
$22
Fuel Cost RecoveryOther regulatory liabilities, current23
—
Purchased Power Capacity RecoveryOther regulatory liabilities, current4
—
Purchased Power Capacity RecoveryUnder recovered regulatory clause revenues—
2
Environmental Cost Recovery(*)
Other regulatory liabilities, current13
—
Environmental Cost Recovery(*)
Under recovered regulatory clause revenues—
2
Energy Conservation Cost RecoveryOther regulatory liabilities, current2
—
(*)At September 30, 2018 and December 31, 2017, the over and under recovered balances, respectively, included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $8 million and $13 million, respectively, net of the over recovered environmental cost recovery balance of approximately $21 million and $11 million, respectively.
On November 5, 2018, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2019. The net effect of the approved changes is a $38 million decrease in annual revenues effective in January 2019, the majority of which will be offset by related expense decreases.
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, which began 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 2013, the Mississippi Public Utilities Staff (MPUS) contested Mississippi Power's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. 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 will also beand 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.

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

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 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 became effective with 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 certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $3 million as of September 30, 2018 and is included in GRAM.other regulatory assets, deferred on Mississippi Power's condensed balance sheet. 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 is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $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 45% at September 30, 2018) to 50% by December 31, 2018. 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. As of September 30, 2018, Mississippi Power has recorded $5 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to PEP.
Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the GRAM approval,2012 PEP lookback filing.
Energy Efficiency
On May 8, 2018, the last monthly Pipeline Replacement Program surchargeMississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.
Ad Valorem Tax Adjustment
On May 8, 2018, the Mississippi PSC also 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.
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 became effective Marchwith the first billing cycle of September 2018 and will continue in effect

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

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 are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not 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. As of September 30, 2018, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form10-K for additional information regarding Mississippi Power's retail fuel cost recovery.
At September 30, 2018, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet in customer accounts receivable was approximately $13 million compared to $6 million under recovered at December 31, 2017.
Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.
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, via bill credits, began on July 1, 2017.2018 related to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. 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."
In September 2016, ElizabethtownNatural Gas filedCost 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 generalsignificant 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
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

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

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 withon or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the New Jersey BPU requestingIllinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a $19result of the Tax Reform Legislation. The resulting decrease of approximately $44 million increase in annual base rate revenues.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 requestedimpact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."
On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected 12-month test year ending March 31, 2017June 30, 2019 and a ROE of 10.25%9.80%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues,The new rates became effective JulyNovember 1, 2017, based on a ROE of 9.6%. Also included2018.
Other
The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the settlement wasstate to defer as a new composite depreciationregulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate that is expected to result in21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a $3 million annual reductiontotal of depreciation. See Note (I) under "Southern Company Gas" for information on the proposed sale of Elizabethtown Gas.
Pending Base Rate Cases
$9 million. On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on aAugust 30, 2018, projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase inan annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROEthe impact of 10.25%. The requested increase included $13 million related to the recoveryflowback of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017,excess deferred income taxes. This filing also proposes for Virginia Natural Gas entered intoto issue customer refunds, via bill credits, for the related amounts deferred as a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates.regulatory asset. The Virginia Commission is expected to rule on the proposed stipulation infiling during the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.
On October 23, 2017, Florida City Gas2018. If approved as filed, a general base rate case with the Florida PSC requesting a $19 million increase inVirginia Natural Gas' annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million torevenues would be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
reduced by $14 million. The ultimate outcome of these pending base rate casesthis 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.

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

Nicor Gas
In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consistsPipeline Replacement Program
One of three individual programs that updatethe capital projects under Atlanta Gas Light's Pipeline Replacement Program experienced construction issues and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million duringwas required to complete mitigation work prior to placing it in service. In the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
In August 2016,quarter 2018, Atlanta Gas Light filed a petition withrecovered $7 million from the Georgia PSC for approvalfinal settlement of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.
See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are beingcontractor litigation claims. Mitigation costs recovered through base rate revenues.
Virginia Naturalthe legal process are retained by Atlanta Gas
In March 2016, Light. For additional information on the Virginia Commission approved an extensionPipeline Replacement Program settlement, see Note 3 to the SAVE program,financial statements of Southern Company Gas under which Virginia Natural Gas invested $21 million during"Regulatory Matters – PRP Settlement" in Item 8 of the first nine months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.Form 10-K.
Integrated Coal Gasification Combined CycleNuclear Construction
See Note 3 to the financial statements of Southern Company and MississippiGeorgia Power under "Integrated Coal Gasification Combined Cycle""Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding MississippiGeorgia Power's construction of Plant Vogtle Units 3 and 4, VCM reports, and the Kemper IGCC.NCCR tariff.
Kemper IGCC Overview
The Kemper IGCC was designed to utilize IGCC technology with an expected output capacityIn 2009, the Georgia PSC certified construction of 582 MWsPlant Vogtle Units 3 and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
4. In 2012, the Mississippi PSCNRC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition,related combined construction and operationoperating licenses, which allowed full construction of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Powertwo AP1000 nuclear units

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

Initiative Round 2 (Initial DOE Grants)(with electric generating capacity of approximately 1,100 MWs each) and excludingrelated facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the costVogtle 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 lignite mineU.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and equipment,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 CO2 pipeline facilities,Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and AFUDCas 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 Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval bytermination (including the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilitiesapplicable portion of the Kemper IGCC in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B"base fee), certain termination-related costs, and, on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operationat certain stages of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component,work, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifierapplicable portion of the Kemper IGCC, givenat-risk fee. Bechtel may terminate the uncertainty asBechtel 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 futureLoan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the gasifier portionBechtel 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 Kemper IGCC. Mississippiremaining 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 September 30, 2018(b)
(4.3)
Remaining estimate to complete(a)
$4.1
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 expects to continue to operate the combined cycle portionestimates that its financing costs for construction of the Kemper IGCC as it has done since August 2014.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, thePlant Vogtle Units 3 and 4 will total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95$3.2 billion, of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants).
Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Powerwhich $1.8 billion had been incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure2018.

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

The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted 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 contract terminationnecessary 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 did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently estimated at approximately $100 million to $200 million are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presentedincluded in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant,construction contingency estimate for rate recovery as and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million iswhen they are appropriately included in other regulatory assets, current and $92 millionthe base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in other regulatory assets, deferred.
Rate Recoverythe construction contingency estimate since the ultimate outcome of Kemper IGCC Costs
Given the variety of potential scenarios and the uncertainty ofthese matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.
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 only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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 Mississippi PSC (andrequirements 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 (ITAAC) and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any subsequent related legal challenges),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 the rate recoverythese matters discussed herein, including the resolution of legal challenges, cannot now be determined but couldat 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 materialchanges 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 that could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.be material.
Kemper IGCC Settlement DocketJoint Owner Contracts
On June 21,In November 2017, the Mississippi PSC stated its intentVogtle Owners entered into an amendment to issue an order (which occurred on July 6, 2017) directing Mississippi Powertheir joint ownership agreements for Plant Vogtle Units 3 and 4 to pursue a settlement under whichprovide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 2018, the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant,Vogtle Owners further amended the joint ownership agreements to clarify and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendmentprovide procedures for certain provisions of the CPCN forjoint ownership agreements related to adverse events that require the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portionvote of the Kemper IGCC, given the uncertainty as to the futureholders of at least 90% of the gasifier portion of the Kemper IGCC. Mississippi Power expectsownership interests in Plant Vogtle Units 3 and 4 to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs

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

associatedconstruction (as amended, and together with the gasification portionsNovember 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 plantincrease in the total project capital cost forecast and lignite mine. Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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 third quarter 2017, Mississippivote to continue construction, Georgia Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension,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 includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedulepartially mitigate potential financial exposure for the Kemper IGCC Settlement Docket,other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as well as mine-relatedfollows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and other suspension4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs through September 30, 2017. Any extensionbetween $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the suspension period beyond December 31, 2017 is currently estimatedother Vogtle Owners will have a one-time option to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017, Mississippi Power has recordedtender a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets,its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includessuch Vogtle Owner's remaining share of total construction costs in excess of the original 2010 estimate forEAC in the combined cyclenineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the facility, as well asownership interest of any other Vogtle Owner. If Georgia Power accepts the 15% that was previously contractedoffer to Cooperative Energy. Mississippi Power has calculatedpurchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects themownership interest(s) to be recovered through rates consistentconveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the Mississippi PSC's requested settlement conditions. The ultimate outcome willsecond and third items described in the paragraph above would be determinedtreated as payments made by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysisapplicable Vogtle Owner.
In the fourth quarter 2016, as a part of its Integrated Resource Plan process,event the Southern Company system completed its regular annual updated fuel forecast,actual costs at completion are less than the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projectionsEAC reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippinineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power filed an updated project economic viability analysiswould be entitled to 60.7% of the Kemper IGCC as required undercost savings with respect to the 2012 MPSC CPCN Order confirming authorizationrelevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the Kemper IGCC. The project economic viability analysis measures the life cycle economicsforegoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast

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

such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a lesser extent,right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC 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, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.
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 Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the estimated Kemper IGCC operatingevent of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs negatively impactit incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the updatedterms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii)

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

PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project economic viability analysis.in lieu of providing such funding.
MississippiThe 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 September 30, 2018, Georgia Power had recovered approximately $1.8 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 expects to file on November 9, 2018 to increase the MississippiNCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.
Georgia Power is required to address this matterfile semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the Kemper IGCC Settlement Docket.
2015 Rate Case
On December 3, 2015,eighth VCM report, the MississippiGeorgia PSC issued the In-Service Asset Rate Order adopting in fullapproved a stipulation entered into between MississippiGeorgia Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costsstaff of the Kemper IGCC relatedGeorgia PSC to waive the 15% undivided interest that was previously projectedrequirement to be purchasedamend 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 Cooperative Energy but reserved Mississippi Power's rightthe Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to seek recoveryapprove a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.
In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementationfifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the In-Service Asset Order$3.3 billion of costs incurred through December 31, 2015 and wholesalereflected 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

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

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 Mississippi Power began expensing certain ongoing project costs and certain retail debtwould be adjusted to include carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forthon those capital costs deemed prudent in the In-Service Asset Rate OrderVogtle 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 settlement agreementROE 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 $680 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 wholesale customers. 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 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.
The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 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.
The ultimate outcome of these matters cannot be determined at this time.
DOE Financing
As of September 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 balance associated withDOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. 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 assets was $113 million,approvals, and satisfaction of which $21 million is includedother conditions. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in current assets. SeeItem 8 of the Form 10-K and Note (F) under "FERC MattersDOE Loan Guarantee Borrowings" herein for additional information, related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculationincluding applicable covenants, events of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.
As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a ratedefault, mandatory prepayment

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

order approving retail rate increasesevents (including any decision not to continue construction of 15% effective March 19, 2013Plant Vogtle Units 3 and 3% effective January 1, 2014, which collectively were designed4), and conditions to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) toborrowing.
The ultimate outcome of these matters cannot be used to mitigate customer rate impacts after the determined at this time.
Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).County Energy Facility
On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDCFor additional information on the Kemper IGCC. BetweenCounty energy facility, see Note 3 to the original May 2014 estimated in-service datefinancial statements of Southern Company and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portionsunder "Kemper County Energy Facility" in Item 8 of the Kemper IGCC.Form 10-K.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. 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. In addition toMine reclamation began in the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred.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 September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 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 $20 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, Mississippi Power constructed the CO2 pipelineperiod costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the planned transportmine and gasifier-related assets, are estimated at $2 million for the remainder of captured CO2 for use2018, $8 million in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury)2019, and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC$4 million annually beginning in service by July 1, 2017.
2020. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Termination of Proposed Sale of Undivided InterestReserve Margin Plan
In 2010 and as amended in 2012,On August 6, 2018, Mississippi Power and Cooperative Energy (formerly knownfiled its proposed RMP, as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interestrequired 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 IGCC. On May 20, 2015, Cooperative Energy notifiedCounty energy facility. Under the RMP, Mississippi Power ofproposes alternatives that would reduce its terminationreserve margin, with the most economic of the agreement.alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-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 previously receivedwould require authorization to defer in a totalregulatory asset for future recovery the remaining net book value of $275 millionthe units at the time of deposits from Cooperative Energy that wereretirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.
Other Matters
Investments in Leveraged Leases
See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) 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 returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory notepaid in full. However, operational issues and the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.resulting cash liquidity challenges persist and significant concerns continue

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

Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016regarding the lessee's ability to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violatedmake the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerningremaining semi-annual lease payments. These operational challenges may also impact the cost and scheduleexpected residual value of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power andassets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit CourtHoldings subsidiary may be unable to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relatingmake its corresponding payment to the Kemper IGCC; askholders of the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any businessunderlying non-recourse debt related to the Kemper IGCCgeneration 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 Mississippi;effect terminating the lease and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017,resulting in the Circuit Court ruledwrite-off of the related lease receivable, which would result in favora reduction in net income of motions byapproximately $86 million after tax based on the lease receivable balance as of September 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and Mississippi Powerthe expected residual value of the generation assets at the end of the lease under various scenarios and dismissedhas concluded that its investment in the case. On July 7, 2017, the plaintiffs filed noticeleveraged lease is not impaired as of an appeal.
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power,September 30, 2018. Southern Company and SCS inwill continue to monitor the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the termsoperational performance of the CO2 contract, whichunderlying assets and evaluate the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Southern Company's and Mississippi Power's resultsability of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in these matters, and the lessee to continue to make the required lease payments. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Baseload ActNatural Gas Storage
In 2008, the Baseload Act was signed by the GovernorA wholly-owned subsidiary of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adoptSouthern Company Gas owns and operates a cost recovery mechanism that includesnatural gas storage facility consisting of two salt dome caverns in retail base rates, prior to and during construction, all or a portionLouisiana. Periodic integrity tests are required in accordance with rules of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passageLouisiana Department of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC.Natural Resources (DNR). In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurredAugust 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 September 30, 2018, the facility's property, plant, and equipment had a net book value of $110 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' 2017 long-lived asset impairment analysis, which determined there was no impairment. Any future changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.
(C)REVENUE FROM CONTRACTS WITH CUSTOMERS
The registrants generate revenues from a variety of sources, some of which are excluded from the scope of ASC 606, such cancelled generating plant.
Income Tax Matters
as leases, derivatives, and certain cost recovery mechanisms. See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle – Bonus Depreciation," " – Investment Tax Credits," and " – Section 174 Research and Experimental Deduction" in Item 8 of the Form 10-K and Note (G)(A) under "Section 174 Research and Experimental DeductionRecently Adopted Accounting Standards – Revenue" for additional information on bonus depreciation, investment tax credits,the adoption of ASC 606 for revenue from contracts with customers.
The majority of the revenues of the traditional electric operating companies and Southern Company Gas are generated from contracts with retail electric and natural gas distribution customers. Revenues from this integrated service to deliver electricity or gas when and if called upon by the Section 174 researchcustomer is recognized as a single performance obligation satisfied over time and experimental deduction.is recognized at a tariff rate as electricity or gas is delivered to the customer during the month. The traditional electric operating companies and Southern Company Gas exclude taxes imposed on the customer and collected on behalf of governmental agencies to be remitted to these agencies from the transaction price in determining the revenue related to contracts with a customer.
The traditional electric operating companies and Southern Power also have contracts with multiple performance obligations, such as capacity and energy in a wholesale PPA, where the contract's total transaction price is allocated

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

Bonus Depreciation
All projected tax benefits previously receivedto each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for bonus depreciationthe 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 Kemper IGCC were repaidcustomer.
The registrants generally have a right to consideration in connectionan amount that corresponds directly with third quarter 2017 estimated tax payments. If the suspensionvalue to the customer of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimedentity's performance completed to date and may recognize revenue in the yearamount to which the entity has a right to invoice and has elected to recognize revenue for its sales of electricity, capacity, and natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the abandonment. See Note (G)registrants' performance obligation.

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

The following tables disaggregate revenue sources for additional information. the three and nine months ended September 30, 2018:
 
For the Three
Months Ended September 30, 2018
For the Nine
Months Ended September 30, 2018
 (in millions)
Southern Company  
Operating revenues  
Retail electric revenues(a)
  
Residential$2,148
$5,266
Commercial1,527
4,084
Industrial901
2,471
Other29
92
Natural gas distribution revenues433
2,299
Alternative revenue programs(b)
5
(23)
Total retail electric and gas distribution revenues$5,043
$14,189
Wholesale energy revenues(c)(d)
516
1,444
Wholesale capacity revenues(d)
177
479
Other natural gas revenues(e)
54
530
Other revenues(f)
369
1,516
Total operating revenues$6,159
$18,158
(a)Retail electric revenues include $17 million and $54 million of leases for the three and nine months ended September 30, 2018, respectively, and a (net reduction) or net increase of $(98) million and $4 million for the three and nine months ended September 30, 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.
(b)See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.
(c)Wholesale energy revenues include $63 million and $217 million for the three and nine months ended September 30, 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.
(d)Wholesale energy and wholesale capacity revenues include $130 million and $31 million, respectively, for the three months ended September 30, 2018 and $318 million and $92 million, respectively, for the nine months ended September 30, 2018 of PPA contracts accounted for as leases.
(e)
Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.
(f)Other revenues include $92 million and $274 million for the three and nine months ended September 30, 2018, respectively, of revenues not accounted for under ASC 606.

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

 Alabama PowerGeorgia Power
Gulf
Power
Mississippi Power
 (in millions)
For the Three Months Ended September 30, 2018    
Operating revenues    
Retail revenues(a)(b)
    
Residential$721
$1,142
$200
$85
Commercial464
877
103
82
Industrial392
385
37
86
Other7
21
1
1
Total retail electric revenues$1,584
$2,425
$341
$254
Wholesale energy revenues(c)
62
33
48
92
Wholesale capacity revenues26
14
7
1
Other revenues(b)(d)
68
121
18
11
Total operating revenues$1,740
$2,593
$414
$358
     
For the Nine Months Ended September 30, 2018    
Operating revenues    
Retail revenues(a)(b)
    
Residential$1,848
$2,671
$537
$209
Commercial1,238
2,343
291
212
Industrial1,103
1,036
100
233
Other19
62
4
6
Total retail electric revenues$4,208
$6,112
$932
$660
Wholesale energy revenues(c)
234
99
104
259
Wholesale capacity revenues75
41
20
6
Other revenues(b)(d)
199
349
50
31
Total operating revenues$4,716
$6,601
$1,106
$956
(a)Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $(12) million, $(47) million, $(36) million, and $(3) million, respectively, for the three months ended September 30, 2018 and $113 million, $(35) million, $(63) million, and $(11) million, respectively, for the nine months ended September 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.
(b)Retail revenues and other revenues at Georgia Power include $17 million and $34 million, respectively, for the three months ended September 30, 2018 and $54 million and $100 million, respectively, for the nine months ended September 30, 2018 of revenues accounted for as leases.
(c)Wholesale energy revenues at Alabama Power and Georgia Power include $6 million and $8 million, respectively, for the three months ended September 30, 2018 and $14 million and $21 million, respectively, for the nine months ended September 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.
(d)Other revenues at Alabama Power, Georgia Power, and Gulf Power include $27 million, $28 million, and $2 million, respectively, for the three months ended September 30, 2018 and $79 million, $80 million, and $5 million, respectively, for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.

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

 
For the Three
Months Ended September 30, 2018
For the Nine
Months Ended September 30, 2018
 (in millions)
Southern Power  
PPA capacity revenues(a)
$168
$450
PPA energy revenues(a)
336
892
Non-PPA revenues(b)
126
347
Other revenues5
10
Total operating revenues$635
$1,699
(a)PPA capacity revenues and PPA energy revenues include $47 million and $139 million, respectively, for the three months ended September 30, 2018 and $141 million and $342 million, respectively, for the nine months ended September 30, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.
(b)Non-PPA revenues include $47 million and $176 million for the three and nine months ended September 30, 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.
 
For the Three
Months Ended September 30, 2018
For the Nine
Months Ended September 30, 2018
 (in millions)
Southern Company Gas  
Operating revenues  
Natural gas distribution revenues  
Residential$149
$1,082
Commercial45
313
Transportation203
708
Industrial4
28
Other32
168
Alternative revenue programs(a)
5
(23)
Total natural gas distribution revenues$438
$2,276
Gas marketing services(b)
44
403
Wholesale gas services(c)
(10)121
Gas midstream operations20
60
Other revenues—
1
Total operating revenues$492
$2,861
(a)See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.
(b)Gas marketing services includes $4 million for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.
(c)
Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.

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

Contract Balances
The ultimate outcomefollowing table reflects the closing balances of this matter cannot be determined at this time.
Section 174 Researchreceivables, contract assets, and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditurescontract liabilities related to revenues from contracts with customers as of September 30, 2018:
 Receivables Contract Assets Contract Liabilities
 (in millions)
Southern Company$2,778
 $99
 $34
Alabama Power649
 1
 14
Georgia Power924
 70
 3
Gulf Power186
 —
 —
Mississippi Power96
 —
 —
Southern Power142
 —
 17
Southern Company Gas523
 —
 1
As of September 30, 2018, Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Georgia Power had contract assets primarily related to fixed retail customer bill programs where the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Companypayment is contingent upon Georgia Power's continued performance and the IRS reachedcustomer's continued participation in the program over the one-year contract term. Southern Power's contract liabilities relate to collections recognized in advance of revenue for certain levelized PPAs with Georgia Power. Southern Company's unregulated distributed generation business had $27 million and $17 million of contract assets and contract liabilities, respectively, remaining for outstanding performance obligations.
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a proposed settlement, which was approved oncustomer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. See Note (G) for additional information.30, 2018 are expected to be recognized as follows:
 20182019202020212022
2023 and
Thereafter
 (in millions)
Southern Company(*)
$168
$406
$322
$322
$310
$2,112
Alabama Power6
22
22
26
23
161
Georgia Power10
41
38
40
30
113
Gulf Power5
22
—
—
—
—
Mississippi Power1
3
3
1
—
—
Southern Power(*)
75
310
283
277
276
2,005
(*)
Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.

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

(C)(D)FAIR VALUE MEASUREMENTS
As of September 30, 2017,2018, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
Fair Value Measurements Using:  Fair Value Measurements Using:  
As of September 30, 2017:
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 September 30, 2018:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
(in millions)(in millions)
Southern Company                  
Assets:                  
Energy-related derivatives(a)(b)
$231
 $184
 $—
 $—
 $415
$271
 $150
 $—
 $—
 $421
Interest rate derivatives—
 5
 —
 —
 5
Foreign currency derivatives—
 103
 —
 —
 103
—
 122
 —
 —
 122
Nuclear decommissioning trusts(c)
752
 1,004
 —
 26
 1,782
828
 1,007
 —
 37
 1,872
Non-qualified deferred compensation trusts:         
Domestic equity—
 11
 —
 —
 11
Foreign equity—
 6
 —
 —
 6
Pooled funds – fixed income—
 13
 —
 —
 13
Cash equivalents1,271
 —
 —
 —
 1,271
15
 —
 —
 —
 15
Other investments9
 —
 1
 —
 10
Other9
 —
 —
 —
 9
Cash equivalents1,309
 —
 —
 —
 1,309
Total$2,263
 $1,296
 $1
 $26
 $3,586
$2,432
 $1,309
 $—
 $37
 $3,778
Liabilities:                  
Energy-related derivatives(a)(b)
$265
 $146
 $—
 $—
 $411
$416
 $159
 $—
 $—
 $575
Interest rate derivatives—
 24
 —
 —
 24
—
 72
 —
 —
 72
Foreign currency derivatives—
 23
 —
 —
 23
—
 23
 —
 —
 23
Contingent consideration—
 —
 20
 —
 20
—
 —
 22
 —
 22
Total$265
 $193
 $20
 $—
 $478
$416
 $254
 $22
 $—
 $692
                  
Alabama Power         
Assets:         
Energy-related derivatives$—
 $9
 $—
 $—
 $9
Nuclear decommissioning trusts:(d)
        

Domestic equity422
 81
 —
 —
 503
Foreign equity60
 57
 —
 —
 117
U.S. Treasury and government agency securities—
 27
 —
 —
 27
Corporate bonds19
 150
 —
 —
 169
Mortgage and asset backed securities—
 18
 —
 —
 18
Private Equity—
 —
 —
 26
 26
Other—
 8
 —
 —
 8
Cash equivalents808
 —
 —
 —
 808
Total$1,309
 $350
 $—
 $26
 $1,685
Liabilities:         
Energy-related derivatives$—
 $7
 $—
 $—
 $7

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

Fair Value Measurements Using:  Fair Value Measurements Using:  
As of September 30, 2017:
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 September 30, 2018:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
(in millions)
Alabama Power         
Assets:         
Energy-related derivatives$—
 $7
 $—
 $—
 $7
Nuclear decommissioning trusts:(d)
        

Domestic equity469
 89
 —
 —
 558
Foreign equity60
 56
 —
 —
 116
U.S. Treasury and government agency securities—
 18
 —
 —
 18
Corporate bonds26
 154
 —
 —
 180
Mortgage and asset backed securities—
 22
 —
 —
 22
Private equity—
 —
 —
 37
 37
Other7
 —
 —
 —
 7
Cash equivalents513
 —
 —
 —
 513
Total$1,075
 $346
 $—
 $37
 $1,458
Liabilities:         
Energy-related derivatives$—
 $10
 $—
 $—
 $10
(in millions)         
Georgia Power                  
Assets:                  
Energy-related derivatives$—
 $18
 $—
 $—
 $18
$—
 $8
 $—
 $—
 $8
Interest rate derivatives—
 1
 —
 —
 1
Nuclear decommissioning trusts:(d) (e)
         
Nuclear decommissioning trusts:(d)(e)
         
Domestic equity235
 1
 —
 —
 236
250
 1
 —
 —
 251
Foreign equity—
 156
 —
 —
 156
—
 134
 —
 —
 134
U.S. Treasury and government agency securities—
 225
 —
 —
 225
—
 236
 —
 —
 236
Municipal bonds—
 64
 —
 —
 64
—
 82
 —
 —
 82
Corporate bonds—
 160
 —
 —
 160
—
 163
 —
 —
 163
Mortgage and asset backed securities—
 38
 —
 —
 38
—
 42
 —
 —
 42
Other16
 19
 —
 —
 35
16
 9
 —
 —
 25
Cash equivalents112
 —
 —
 —
 112
350
 —
 —
 —
 350
Total$363
 $682
 $—
 $—
 $1,045
$616
 $675
 $—
 $—
 $1,291
Liabilities:                  
Energy-related derivatives$—
 $11
 $—
 $—
 $11
$—
 $22
 $—
 $—
 $22
Interest rate derivatives—
 3
 —
 —
 3
—
 6
 —
 —
 6
Total$—
 $14
 $—
 $—
 $14
$—
 $28
 $—
 $—
 $28
                  
Gulf Power                  
Assets:                  
Cash equivalents$21
 $—
 $—
 $—
 $21
$27
 $—
 $—
 $—
 $27
Liabilities:                  
Energy-related derivatives$—
 $22
 $—
 $—
 $22
$—
 $8
 $—
 $—
 $8
                  
Mississippi Power         
Assets:         
Energy-related derivatives$—
 $3
 $—
 $—
 $3
Interest rate derivatives—
 2
 —
 —
 2
Cash equivalents209
 —
 —
 —
 209
Total$209
 $5
 $—
 $—
 $214
Liabilities:         
Energy-related derivatives$—
 $7
 $—
 $—
 $7
         

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

Fair Value Measurements Using:  Fair Value Measurements Using:  
As of September 30, 2017:
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 September 30, 2018:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
(in millions)
Mississippi Power         
Assets:         
Energy-related derivatives$—
 $3
 $—
 $—
 $3
Cash equivalents346
 —
 —
 —
 346
Total$346
 $3
 $—
 $—
 $349
Liabilities:         
Energy-related derivatives$—
 $9
 $—
 $—
 $9
(in millions)         
Southern Power                  
Assets:                  
Energy-related derivatives$—
 $9
 $—
 $—
 $9
$—
 $3
 $—
 $—
 $3
Foreign currency derivatives—
 103
 —
 —
 103
—
 122
 —
 —
 122
Cash equivalents90
 —
 —
 —
 90
Total$90
 $112
 $—
 $—
 $202
$—
 $125
 $—
 $—
 $125
Liabilities:                  
Energy-related derivatives$—
 $4
 $—
 $—
 $4
$—
 $7
 $—
 $—
 $7
Foreign currency derivatives—
 23
 —
 —
 23
—
 23
 —
 —
 23
Contingent consideration—
 —
 20
 —
 20
—
 —
 22
 —
 22
Total$—

$27

$20

$—

$47
$—

$30

$22

$—

$52
                  
Southern Company Gas                  
Assets:                  
Energy-related derivatives(a)(b)
$231
 $145
 $—
 $—
 $376
$271
 $129
 $—
 $—
 $400
Non-qualified deferred compensation trusts:         
Domestic equity—
 11
 —
 —
 11
Foreign equity—
 6
 —
 —
 6
Pooled funds – fixed income—
 13
 —
 —
 13
Cash equivalents4
 —
 —
 —
 4
Cash equivalents26
 —
 —
 —
 26
Total$301

$159

$—

$—

$460
Liabilities:                  
Energy-related derivatives(a)(b)
$265
 $95
 $—
 $—
 $360
$416
 $101
 $—
 $—
 $517
(a)Excludes $13$5 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)Excludes cash collateral of $76$189 million.
(c)For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.
(d)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.
(e)Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2017,2018, approximately $66$37 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.

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 $50 million and $168 million, respectively, for the three and nine months ended September 30, 2018 and 2017 and by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016. Alabama Poweramounts shown in the table below. The increases were recorded increases in fair value of $25 million and $87 million, respectively, for the three and nine months ended September 30, 2017 and $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 as a change into the regulatory assets and liabilities related to its AROs.AROs for Georgia Power recorded increases in fair value of $25 million and $81 million, respectively, for the three and nine months ended September 30, 2017 and $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 as a change in its regulatory asset related to its AROs.Alabama Power, respectively.
 
Three Months Ended
September 30, 2018
Three Months Ended
September 30, 2017
Nine Months Ended
September 30, 2018
Nine Months Ended
September 30, 2017
 (in millions)
Southern Company$58
$50
$68
$168
Alabama Power39
25
49
87
Georgia Power19
25
19
81
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

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

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 (H)(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 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 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, over a period ranging from 10 to 30 years, beginningwhich commenced at the commercial operation date.date of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically.

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

rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of September 30, 2017,2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusttrusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
As of September 30, 2017:
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
As of September 30, 2018:
Fair
Value
 
Unfunded
Commitments
(in millions) (in millions)
Southern Company$26
 $24
 Not Applicable Not Applicable$37
 $47
Alabama Power$26
 $24
 Not Applicable Not Applicable$37
 $47
Private equity funds include a fund-of-fundsfunds-of-funds that investsinvest in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.

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

As of September 30, 2017,2018, other financial instruments for which the carrying amount did not equal fair value were as follows:
Carrying
Amount
 
Fair
Value
Carrying
Amount
 
Fair
Value
(in millions)(in millions)
Long-term debt, including securities due within one year:      
Southern Company$47,269
 $49,348
$45,524
 $45,500
Alabama Power$7,404
 $8,031
8,120
 8,321
Georgia Power$11,713
 $12,237
10,227
 10,159
Gulf Power$1,292
 $1,352
1,285
 1,290
Mississippi Power$2,123
 $2,117
1,736
 1,702
Southern Power$5,810
 $5,916
5,029
 5,058
Southern Company Gas$5,862
 $6,230
5,908
 5,935
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.

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

(D)(E)STOCKHOLDERS' EQUITY
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance sharestock-based compensation plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance sharestock-based compensation plans. The effect of both stock options and performance share award unitsstock-based compensation plans was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
Three Months Ended September 30, 2017Three Months Ended September 30, 2016Nine Months Ended September 30, 2017Nine Months Ended September 30, 2016Three Months Ended
September 30, 2018		Three Months Ended
September 30, 2017		Nine Months Ended
September 30, 2018		Nine Months Ended
September 30, 2017
(in millions)(in millions)
As reported shares1,003
968
998
940
1,023
1,003
1,016
998
Effect of options and performance share award units7
7
7
5
Effect of stock-based compensation6
7
5
7
Diluted shares1,010
975
1,005
945
1,029
1,010
1,021
1,005
Stock options and performance share award unitsStock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three and nine months ended September 30, 20172018 and 2016.2017.

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

Changes in Stockholders' Equity
The following table presents year-to-date changes in stockholders' equity of Southern Company:
Number of
Common Shares
 Common
Stockholders'
Equity
Preferred and
Preference
Stock of
Subsidiaries
 Total
Stockholders'
Equity
Number of
Common Shares
 Common
Stockholders'
Equity
Preferred and
Preference
Stock of
Subsidiaries
 Total
Stockholders'
Equity
IssuedTreasury 
Noncontrolling Interests(*)
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—
—
 1,948
—
—
1,948
Other comprehensive income—
—
 52
—
—
52
Stock issued21,342
—
 878
—
—
878
Stock-based compensation—
—
 74
—
—
74
Cash dividends on common stock—
—
 (1,805)—
—
(1,805)
Contributions from noncontrolling interests—
—
 —
—
154
154
Distributions to noncontrolling interests—
—
 —
—
(87)(87)
Net income attributable to noncontrolling interests—
—
 —
—
71
71
Sale of noncontrolling interests(b)
—
—
 (410)—
1,690
1,280
Other—
(57) (27)—
(1)(28)
Balance at September 30, 20181,029,874
(986) $24,877
$—
$3,188
$28,065
(in thousands) (in millions)   
Balance at December 31, 2016991,213
(819) $24,758
$609
$1,245
$26,612
991,213
(819) $24,758
$609
$1,245
$26,612
Consolidated net income attributable to Southern Company—
—
 347
—
—
347
—
—
 347
—
—
347
Other comprehensive income (loss)—
—
 (2)—
—
(2)—
—
 (2)—
—
(2)
Stock issued13,308
—
 613
—
—
613
13,308
—
 613
—
—
613
Stock-based compensation—
—
 97
—
—
97
—
—
 97
—
—
97
Cash dividends on common stock—
—
 (1,716)—
—
(1,716)—
—
 (1,716)—
—
(1,716)
Preference stock redemption—
—
 —
(150)—
(150)—
—
 —
(150)—
(150)
Contributions from noncontrolling interests—
—
 —
—
77
77
—
—
 —
—
77
77
Distributions to noncontrolling interests—
—
 —
—
(87)(87)—
—
 —
—
(87)(87)
Net income attributable to noncontrolling interests—
—
 —
—
45
45
—
—
 —
—
45
45
Reclassification from redeemable noncontrolling interests—
—
 —
—
114
114
—
—
 —
—
114
114
Other—
(75) (15)3
1
(11)—
(75) (15)3
1
(11)
Balance at September 30, 20171,004,521
(894) $24,082
$462
$1,395
$25,939
1,004,521
(894) $24,082
$462
$1,395
$25,939
   
Balance at December 31, 2015915,073
(3,352) $20,592
$609
$781
$21,982
Consolidated net income attributable to Southern Company—
—
 2,251
—
—
2,251
Other comprehensive income (loss)—
—
 (95)—
—
(95)
Stock issued65,725
2,599
 3,265
—
—
3,265
Stock-based compensation—
—
 94
—
—
94
Cash dividends on common stock—
—
 (1,553)—
—
(1,553)
Contributions from noncontrolling interests—
—
 —
—
357
357
Distributions to noncontrolling interests—
—
 —
—
(21)(21)
Purchase of membership interests from noncontrolling interests—
—
 —
—
(129)(129)
Net income attributable to noncontrolling interests—
—
 —
—
36
36
Other—
(46) (7)—
—
(7)
Balance at September 30, 2016980,798
(799) $24,547
$609
$1,024
$26,180
(*)(a)RelatedPrimarily related to Southern Power Company and excludes redeemable noncontrolling interests. In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
(b)
See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

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

(E)(F)FINANCING
Going ConcernBank Credit Arrangements
AsBank 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 September 30, 2017,2018 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to approximately $935 million that will be required throughPower). In addition, at September 30, 2018, to fund maturitiesthe traditional electric operating companies had approximately $573 million (comprised of long-term debt and $4approximately $120 million that will be required to fund maturities of short-term debt. In addition, Mississippiat Alabama Power, has $40$345 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilitiesat Georgia Power, $58 million at Gulf Power, and $50 million at Mississippi Power) of fixed raterevenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held its approximately $120 million of outstanding pollution control revenue bonds that are required to be remarketed over the next 12 months. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 andremarketed. See Note 6 to the financial statements of Mississippi Powereach registrant under "Recently Issued Accounting Standards" and "Going Concern," respectively,"Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined CycleFinancing Activities." herein for additional information.
The following table outlines the committed credit arrangements by company as of September 30, 2018:
 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 Power—
33
500
800
 1,333
 1,333
 —
 —
 33
Georgia Power—
—
—
1,750
 1,750
 1,736
 —
 —
 —
Gulf Power20
25
235
—
 280
 280
 45
 45
 —
Mississippi Power—
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$20
$188
$735
$7,200
 $8,143
 $8,101
 $45
 $45
 $63
(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 2019, of which $22 million remains unused at September 30, 2018.
(c)
Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
DOE Loan Guarantee Borrowings
See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.Agreement.
On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related

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

intellectual property licenses (IP Licenses).
Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until such time as Georgia Power hascertain conditions are satisfied, including (i) completed the cost-to-complete and cancellation cost assessments prepared as a resultreceipt of the bankruptcyDOE's approval of the EPC Contractor (Cost Assessments) and made a determination to continue construction of Plant Vogtle Units 3 and 4, (ii) delivered to the DOE an updated project schedule, construction budget, and other information, (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Plant Vogtle Units 3 and 4 and such agreements have been approved by the DOEBechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered(ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Upon satisfaction ofIn September 2017, the conditions described above, advances may be requestedDOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance underLoan Guarantee Agreement. In September 2018, the FFB Credit Facility is February 20, 2044. Interest is payable quarterlyDOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and principal payments will begin on February 20, 2020. Borrowings underissuance of these additional loan guarantees by the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
In addition to the conditions described above, future advancesDOE 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 customary conditions, as well as certificationother conditions.
As of compliance withSeptember 30, 2018, Georgia Power had $2.6 billion of borrowings outstanding under the requirements ofmulti-advance term loan facility (FFB Credit Facility) among Georgia Power, the Title XVII Loan Guarantee Program, accuracy of project-related representationsDOE, and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, 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.

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

FFB.
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4) occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) a failure by Georgia Power to complete the Cost Assessments or enter into Replacement EPC Arrangements by December 31, 2017; (iv) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (v)(iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, under certain circumstancesif Georgia Power maydiscontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be requiredobligated to make additional prepayments in connection with its receiptimmediately repay a portion of paymentsthe outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement or from the EPC Contractor under the Vogtle 3 and 4 Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
On September 28, 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. 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.
See Note (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2017 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 million (comprised of approximately $509 million at Georgia Power, $140 million at Gulf Power, and $50 million at Mississippi Power) of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode. 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.

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

The following table outlines the committed credit arrangements by company as of September 30, 2017:
 Expires   
Executable Term
Loans
 
Expires Within
One Year
Company20172018201920202022 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
 (in millions)
Southern Company(a)
$—
$—
$—
$—
$2,000
 $2,000
 $2,000
 $—
 $—
 $—
 $—
Alabama Power—
35
—
500
800
 1,335
 1,335
 —
 —
 —
 35
Georgia Power—
—
—
—
1,750
 1,750
 1,732
 —
 —
 —
 —
Gulf Power30
195
25
30
—
 280
 280
 45
 —
 —
 40
Mississippi Power100
—
—
—
—
 100
 100
 —
 —
 —
 100
Southern Power Company(b)
—
—
—
—
750
 750
 728
 —
 —
 —
 —
Southern Company Gas(c)
—
—
—
—
1,900
 1,900
 1,861
 —
 —
 —
 —
Other—
30
—
—
—
 30
 30
 20
 —
 20
 10
Southern Company Consolidated$130
$260
$25
$530
$7,200
 $8,145
 $8,066
 $65
 $—
 $20
 $185
(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 $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.
(c)
Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.
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.

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 nine months of 2017:2018:
CompanySenior Note Issuances 
Senior
Note Maturities and Redemptions
 
Revenue
Bond
Maturities, Redemptions, and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term Debt Redemptions
and
Maturities(a)
Senior
Note
Issuances
 Senior Note Maturities, Redemptions, and Repurchases 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)
$300
 $400
 $—
 $500
 $400
$750
 $1,000
 $—
 $—
 $—
Alabama Power550
 200
 36
 —
 —
500
 —
 —
 —
 —
Georgia Power1,350
 450
 65
 370
 13
—
 1,000
 469
 —
 107
Gulf Power300
 85
 —
 6
 —
Mississippi Power—
 —
 —
 40
 893
600
 —
 43
 —
 900
Southern Power—
 —
 —
 43
 4
—
 350
 —
 —
 420
Southern Company Gas(c)
450
 —
 —
 200
 22
Southern Company Gas—
 —
 200
 100
 —
Other—
 —
 —
 —
 12
—
 —
 —
 —
 10
Elimination(d)
—
 —
 —
 (40) (599)
Elimination(c)
—
 —
 —
 —
 (1)
Southern Company Consolidated$2,950
 $1,135
 $101
 $1,119
 $745
$1,850
 $2,350
 $712
 $100
 $1,436
(a)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(b)Represents the Southern Company parent entity.
(c)
The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.
(d)Includes intercompany loans from Southern Company to Mississippi Power andRepresents reductions in affiliate capital lease obligations at Georgia Power. These transactionsPower, which are eliminated in Southern Company's Consolidated Financial Statements.
Southern Company
In June 2017,Except as otherwise described herein, Southern Company issued $500 million aggregate principal amountand its subsidiaries used the proceeds of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057debt issuances for their redemptions and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were usedmaturities shown in the table above, to repay short-term indebtedness, and for other general corporate purposes.purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.
Also in June 2017,Southern Company
In March 2018, Southern Company entered into two $100a $900 million aggregate principal amountshort-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bearbearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.LIBOR, which was repaid in August 2018.
In August 2017,April 2018, Southern Company borrowed $250 million pursuant to ana short-term uncommitted bank credit arrangement, which bearsbearing interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.
Alabama Power
In March 2017, Alabama PowerJune 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.
In August 2018, Southern Company issued $550$750 million aggregate principal amount of Series 2017A 2.45%2018A Floating Rate Senior Notes due March 30, 2022. The proceeds were usedFebruary 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to repay a short-term uncommitted bank credit arrangement.
Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.Power
In September 2017,June 2018, Alabama Power issued 10 million shares ($250$500 million aggregate stated capital)principal amount of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used inSeries 2018A 4.30% Senior Notes due July 15, 2048.

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

October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Georgia Power
In March 2017,January 2018, Georgia Power issued $450repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
In April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2017A 2.00%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 30, 20201, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $400$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.
During 2018, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion2013
$173 million aggregate principal amount of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009
In April 2017, Georgia Power purchased and held $27$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.1994
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.2008
Also in August 2017, Georgia Power purchased and held $38$71.735 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia2013
Mississippi Power remarketed these bonds to the public.
In September 2017, GeorgiaMarch 2018, Mississippi Power issued $270$300 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated2018A Floating Rate Senior Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate liquidation amount)principal amount of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
Gulf Power
2018B 3.95% Senior Notes due March 30, 2028. In March 2017, Gulf2018, Mississippi Power extended the maturity ofalso entered into a $100$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 $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from April 2017these financings to October 2017 and subsequently repaid the loan in May 2017.repay a $900 million unsecured term loan.
In May 2017, GulfJuly 2018, Mississippi Power issued $300purchased and held approximately $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2017A 3.30% Senior Notes due May2002. Mississippi Power may reoffer these bonds to the public at a later date.
Subsequent to September 30, 2027. The proceeds, together with other funds, were used to repay at maturity $852018, Mississippi Power completed the redemption of all 8,867 outstanding shares ($886,700 aggregate par value) of its 4.40% Series Preferred Stock, all 8,643 outstanding shares ($864,300 aggregate par value) of its 4.60% Series Preferred Stock, all 16,700 outstanding shares ($1.67 million aggregate par value) of its 4.72% Series Preferred Stock, all 1,200,000 outstanding depositary shares ($30 million aggregate stated value) each representing a 1/4th interest in a share of its 5.25% Series Preferred Stock, all $30 million aggregate principal amount outstanding of its Series 2007A 5.90%G 5.40% Senior Notes due June 15, 2017; to repayJuly 1, 2035, and all $125 million aggregate principal amount outstanding commercial paper borrowings; to repay a $100 millionof its Series 2009A 5.55% Senior Notes due March 1, 2019.
Southern Power
In May 2018, Southern Power entered into two short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55loans, each for an aggregate principal amount of $100 million, aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock,which bear interest based on one-month LIBOR.

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

and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
Mississippi Power
In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi2018, Southern Power borrowed an additional $40repaid $420 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstandingaggregate principal amount of promissory noteslong-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018.
During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to the Gaskell West 1 and Cactus Flats facilities. See Note (J) under "Southern Power" for additional information.
Southern Company; and (iii) repay a $10 million short-term bank loan.Company Gas
In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.
In September 2017, Mississippi PowerOn January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150$100 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) under "Section 174 Research and Experimental Deduction" for additional information.
Southern Power
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
Southern Company Gas
In May 2017,On March 28, 2018, Southern Company Gas Capital issued $450repaid this promissory note.
Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of Series 2017A 4.40% Senior Notes duegas facility revenue bonds to be redeemed.
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 2047.days' demand by the bank. The proceeds of the loan were used to repay short-term debt. In July 2018, Southern Company Gas' short-term indebtedness and for general corporate purposes.Gas Capital repaid this loan.
In July 2017,2018, Nicor Gas agreed to issue $400$300 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issuedplacement, $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series duewhich was issued in August 10, 20272018 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to beof which was issued in November 2017.2018.
(F)(G)RETIREMENT BENEFITS
On January 1, 2018, the qualified defined benefit pension plan of Southern Company Gas was merged into the qualified defined benefit pension plan of Southern Company. Following the plan merger, Southern Company has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified defined benefit pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the Southern Company qualified defined benefit pension plan are anticipated for the year ending December 31, 2017.2018.
In addition, the Southern Company also providesGas 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 benefit pension plansbenefits for a selectedselect group of management and highly compensated employees. Benefits under these non-qualified pension plansemployees, which are funded on a cash basis. In addition,
Furthermore, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric

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

operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
SeeAs indicated in Note 2(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 financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power,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 Southern Company Gasmaintenance and all other components of net periodic benefit costs included in Item 8other income (expense), net in the statements of income for the Form 10-K for additional information.three and nine months ended September 30, 2017.

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

With respect to the presentation requirements, the registrants have used the practical expedient provided by ASU 2017-07, which permits an employer to use the amounts disclosed in its retirement benefits footnote for prior comparative periods as the estimation basis for applying the retrospective presentation requirements to those periods. The amounts of the other components of net periodic benefit costs reclassified for the prior period are presented in the following tables.
See Note 2 to the financial statements of each registrant in Item 8 of the Form 10-K for additional information.
Components of the net periodic benefit costs for the three and nine months ended September 30, 20172018 and 20162017 are presented in the following tables.
Three Months Ended September 30, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
(in millions)
Pension Plans
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
Pension Plans
(in millions)
Three Months Ended September 30, 2017         
Service cost$73
 $15
 $19
 $3
 $4
$90
 $19
 $22
 $4
 $5
 $3
 $8
Interest cost114
 25
 34
 5
 5
116
 26
 34
 5
 5
 1
 10
Expected return on plan assets(224) (49) (71) (10) (9)(236) (51) (74) (10) (11) (3) (18)
Amortization:                      
Prior service costs3
 1
 —
 —
 —
1
 —
 1
 —
 —
 —
 (1)
Regulatory asset—
 —
 —
 —
 —
 —
 4
Net (gain)/loss41
 10
 15
 2
 1
53
 13
 18
 2
 3
 —
 3
Net periodic pension cost (income)$7
 $2
 $(3) $—
 $1
$24
 $7
 $1
 $1
 $2
 $1
 $6
Nine Months Ended September 30, 2017         
Postretirement BenefitsPostretirement Benefits
Service cost$220
 $47
 $56
 $10
 $11
$6
 $1
 $2
 $—
 $—
 $1
 $—
Interest cost341
 73
 103
 15
 15
19
 5
 7
 1
 —
 —
 2
Expected return on plan assets(673) (147) (212) (29) (29)(17) (7) (6) —
 —
 —
 (1)
Amortization:                      
Prior service costs9
 2
 2
 —
 1
2
 1
 —
 —
 —
 —
 —
Regulatory asset—
 —
 —
 —
 —
 —
 2
Net (gain)/loss122
 31
 43
 5
 5
3
 —
 2
 —
 —
 —
 —
Net periodic pension cost (income)$19
 $6
 $(8) $1
 $3
Three Months Ended September 30, 2016         
Service cost$68
 $14
 $17
 $3
 $3
Interest cost110
 23
 34
 5
 4
Expected return on plan assets(203) (46) (64) (9) (9)
Amortization:         
Prior service costs3
 1
 1
 —
 1
Net (gain)/loss45
 10
 14
 2
 2
Net periodic pension cost$23
 $2
 $2
 $1
 $1
Nine Months Ended September 30, 2016         
Service cost$192
 $43
 $52
 $9
 $9
Interest cost311
 71
 102
 14
 14
Expected return on plan assets(577) (138) (193) (26) (26)
Amortization:         
Prior service costs10
 2
 4
 1
 1
Net (gain)/loss120
 30
 41
 5
 5
Net periodic pension cost$56
 $8
 $6
 $3
 $3
Net periodic postretirement benefit cost$13
 $—
 $5
 $1
 $—
 $1
 $3

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

Nine Months Ended September 30, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
(in millions)
Pension Plans
Southern
Company
Gas
Pension Plans
(in millions)
Successor – Three Months Ended September 30, 2017 
Service cost$6
Interest cost10
Expected return on plan assets(18)
Amortization of net (gain)/loss5
Net periodic pension cost$3
Successor – Nine Months Ended September 30, 2017 
Service cost$17
$269
 $58
 $65
 $12
 $13
 $7
 $24
Interest cost30
348
 76
 104
 15
 15
 4
 29
Expected return on plan assets(53)(707) (155) (222) (30) (31) (8) (53)
Amortization:              
Prior service costs(1)3
 1
 2
 —
 —
 —
 (2)
Regulatory asset—
 —
 —
 —
 —
 —
 11
Net (gain)/loss15
160
 40
 52
 7
 8
 1
 9
Net periodic pension cost$8
Successor – July 1, 2016 through September 30, 2016 
Service cost$7
Interest cost10
Expected return on plan assets(17)
Amortization of regulatory asset6
Net periodic pension cost$6
 
 
Predecessor – January 1, 2016 through June 30, 2016 
Net periodic pension cost (income)$73
 $20
 $1
 $4
 $5
 $4
 $18
Postretirement BenefitsPostretirement Benefits
Service cost$13
$18
 $4
 $5
 $1
 $1
 $1
 $1
Interest cost21
56
 13
 21
 2
 2
 —
 7
Expected return on plan assets(33)(51) (20) (19) (1) (1) —
 (5)
Amortization:              
Prior service costs(1)5
 3
 1
 —
 —
 —
 —
Regulatory asset—
 —
 —
 —
 —
 —
 5
Net (gain)/loss13
10
 1
 6
 —
 —
 —
 —
Net periodic pension cost$13
Net periodic postretirement benefit cost$38
 $1
 $14
 $2
 $2
 $1
 $8

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

Three Months Ended
September 30, 2017(*)
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Company Gas
(in millions)
Pension PlansPension Plans
Service cost$73

$15

$19

$3

$4

$6
Interest cost114

25

34

5

5

10
Expected return on plan assets(224)
(49)
(71)
(10)
(9)
(18)
Amortization:           
Prior service costs3

1

—

—

—

—
Net (gain)/loss41

10

15

2

1

5
Net periodic pension cost (income)$7

$2

$(3)
$—

$1

$3
Postretirement Benefits
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
Postretirement Benefits
(in millions)
Three Months Ended September 30, 2017         
Service cost$6
 $1
 $2
 $—
 $—
$6
 $1
 $2
 $—
 $—
 $1
Interest cost19
 4
 6
 1
 1
19
 4
 6
 1
 1
 3
Expected return on plan assets(16) (5) (6) —
 —
(16) (5) (6) —
 —
 (2)
Amortization:                    
Prior service costs2
 1
 —
 —
 —
2
 1
 —
 —
 —
 (1)
Net (gain)/loss3
 —
 3
 —
 —
3
 —
 3
 —
 —
 1
Net periodic postretirement benefit cost$14
 $1
 $5
 $1
 $1
$14
 $1
 $5
 $1
 $1
 $2
Nine Months Ended September 30, 2017         
Service cost$18
 $4
 $5
 $1
 $1
Interest cost59
 13
 21
 2
 3
Expected return on plan assets(49) (19) (18) (1) (1)
Amortization:         
Prior service costs5
 3
 1
 —
 —
Net (gain)/loss10
 1
 6
 —
 —
Net periodic postretirement benefit cost$43
 $2
 $15
 $2
 $3
Three Months Ended September 30, 2016         
Service cost$6
 $1
 $2
 $—
 $—
Interest cost20
 5
 7
 1
 —
Expected return on plan assets(16) (6) (6) —
 —
Amortization:         
Prior service costs1
 1
 —
 —
 —
Net (gain)/loss5
 —
 3
 —
 1
Net periodic postretirement benefit cost$16
 $1
 $6
 $1
 $1
Nine Months Ended September 30, 2016         
Service cost$17
 $4
 $5
 $1
 $1
Interest cost55
 14
 22
 2
 2
Expected return on plan assets(44) (19) (17) (1) (1)
Amortization:         
Prior service costs4
 3
 1
 —
 —
Net (gain)/loss12
 1
 7
 —
 1
Net periodic postretirement benefit cost$44
 $3
 $18
 $2
 $3

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

(*)Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.
Nine Months Ended
September 30, 2017(*)
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Company Gas
(in millions)
Pension PlansPension Plans
Service cost$220
 $47
 $56
 $10
 $11
 $17
Interest cost341
 73
 103
 15
 15
 30
Expected return on plan assets(673) (147) (212) (29) (29) (53)
Amortization:           
Prior service costs9
 2
 2
 —
 1
 (1)
Net (gain)/loss122
 31
 43
 5
 5
 15
Net periodic pension cost (income)$19
 $6
 $(8) $1
 $3
 $8
Postretirement Benefits
Southern
Company
Gas
Postretirement Benefits
(in millions)
Successor – Three Months Ended September 30, 2017 
Service cost$1
$18
 $4
 $5
 $1
 $1
 $2
Interest cost3
59
 13
 21
 2
 3
 8
Expected return on plan assets(2)(49) (19) (18) (1) (1) (5)
Amortization:            
Prior service costs(1)5
 3
 1
 —
 —
 (2)
Net (gain)/loss1
10
 1
 6
 —
 —
 3
Net periodic postretirement benefit cost$2
$43
 $2
 $15
 $2
 $3
 $6
Successor – Nine Months Ended September 30, 2017 
Service cost$2
Interest cost8
Expected return on plan assets(5)
Amortization: 
Prior service costs(2)
Net (gain)/loss3
Net periodic postretirement benefit cost$6
Successor – July 1, 2016 through September 30, 2016 
Service cost$1
Interest cost2
Expected return on plan assets(2)
Amortization of regulatory asset1
Net periodic postretirement benefit cost$2
 
 
Predecessor – January 1, 2016 through June 30, 2016 
Service cost$1
Interest cost5
Expected return on plan assets(3)
Amortization: 
Prior service costs(1)
Net (gain)/loss2
Net periodic postretirement benefit cost$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)

(G)(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 $1.9$2.4 billion as of September 30, 20172018 compared to $1.8$2.1 billion as of December 31, 2016.2017.
The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2022.2023. The PTC carryforwards begin expiringestimated tax credit utilization reflects the 2018 abandonment loss related to certain Kemper County energy facility expenditures as well as the projected taxable gains on the various sale transactions described in 2036 but are expected to be utilized by 2022.Note (J) and "Legal Entity Reorganizations" herein. The expected utilization of tax credit carryforwards could be further delayed by numerous factors. These factors, includeincluding the acquisition of additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss,purchase of rights to additional PTCs during construction of Plant Vogtle Units 3 and potential tax reform legislation, as well as4 pursuant to the MEAG Term Sheet, and changes in taxable income projections. See Note (B) under "Nuclear Construction" for additional deductions in the event of an asset abandonment.information on Plant Vogtle Units 3 and 4. The ultimate outcome of these matters cannot be determined at this time.
Valuation Allowances
At September 30, 2017, valuation allowances were as follows:
Mississippi Power 
Southern Company
Gas
 Southern Company
Georgia
Power
 Mississippi Power Southern Company Gas Southern Company
(in millions)(in millions)
Federal$—
 $18
 $18
$6
 $—
 $11
 $19
State (net of federal benefit)46
 1
 64
33
 124
 1
 171
Balance at September 30, 2017$46
 $19
 $82
Balance at September 30, 2018$39
 $124
 $12
 $190
Southern Company had valuation allowances, net of therelated federal benefit,benefits, of $82$190 million at September 30, 20172018 compared to $21$148 million at December 31, 2016.2017. The increase was primarily due to MississippiGeorgia Power's projected inability to utilize the State of Mississippi net operating loss.certain state tax credit carryforwards.
Effective Tax Rate
Each registrant's effective tax rate for the nine months ended September 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.

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

Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs.
Southern Company's effective tax rate was 42.6%22.7% for the nine months ended September 30, 20172018 compared to 28.3%42.6% for the corresponding period in 2016.2017. The effective tax rate increasedecrease was primarily due to the estimated probable lossesreduction 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, the net state income tax benefits related to changes in state apportionment rates arising from the reorganization of Southern Power's legal entities as discussed further herein, and the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include a decreaseportion, recorded in tax benefits from solar ITCs and an increase in state valuation allowances,2017, partially offset by an increasethe $1.1 billion pre-tax loss related to Plant Vogtle Units 3 and 4 and the income taxes recorded related to the Southern Company Gas Dispositions in tax benefits from wind PTCs.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) 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 and Note (J) under "Southern Company Gas" for additional information on the Southern Company Gas Dispositions.
Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Alabama Power
Alabama Power's effective tax rate was 23.9% for the nine months ended September 30, 2018 compared to 39.9% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Alabama Power" for additional information.
Georgia Power
Georgia Power's effective tax rate was 25.5% for the nine months ended September 30, 2018 compared to 37.0% 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 $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 valuation allowance on certain state tax credit carryforwards. See Note (B) under "Nuclear Construction" for additional information.
Gulf Power
Gulf Power's effective tax benefit rate was (0.5)% for the nine months ended September 30, 2018 compared to an effective tax rate of 39.4% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Gulf Power" for additional information.
Mississippi Power
Mississippi Power's effective tax rate was 20.8% for the nine months ended September 30, 2018 compared to a benefit rate of (30.3)% 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.

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

MississippiSouthern Power
MississippiSouthern Power's effective tax (benefit)benefit rate was (30.3)(220.3)% for the nine months ended September 30, 20172018 compared to (282.8)(66.5)% for the corresponding period in 2016.2017. The effective tax rate increasedecrease was primarily due to the estimated probable losses on the Kemper IGCC, netlower earnings before income taxes resulting from a $119 million asset impairment charge as a result of the non-deductible AFUDC equity portionpending sale of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and a $36 million asset impairment charge on wind turbine equipment held for development projects, as well as the reduction in the federal corporate income tax rate and the net state income tax benefits related state valuation allowances.
Southern Power
to certain changes in apportionment rates arising from the reorganization of Southern Power's effective tax (benefit) rate was (66.5)%legal entities as described below. See Note (J) under "Southern Power" for the nine months ended September 30, 2017 compared to (88.9)% for the corresponding period in 2016. The effective tax rate increase was primarily due to a decrease in tax benefits from solar ITCs, partially offset by additional wind PTCs and state apportionment rate changes.information.
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.
DuringSouthern Company Gas
Southern Company Gas' effective tax rate was 61.8% for the third quarternine months ended September 30, 2018 compared to 43.4% for the corresponding period in 2017. This increase was primarily related to income taxes recorded related to the Southern Company Gas Dispositions, 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, as well as the 2017 increases in deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states. See Note (B) under "Regulatory Matters – Southern Company Gas" and Note (J) under "Southern Company Gas" for additional information.
Legal Entity Reorganizations
In April 2018, Southern Power begancompleted the final stage of 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. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to resultresulted in estimatednet state tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates andtotaling approximately $54 million, which were recorded in the first half of 2018.
In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
Southern Company Gas' effective tax rate was 43.4% for the successor nine months ended September 30, 2017 compared to 60.3% for the successor period of July 1, 2016 through September 30, 2016 and 37.6% for the predecessor period of January 1, 2016 through June 30, 2016. The effective tax rate for the successor year-to-date 2017 was impacted by State of Illinois tax legislation enacted during July 2017, the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, and higher pre-tax earnings. The effective tax rates for the periodsbenefits totaling approximately $11 million related to certain changes in 2016 were impacted by the non-deductibility of certain Merger-related expenses. The effective tax rate for the successor period of July 1, 2016 through September 30, 2016 was also impacted by nondeductible expenses associated with certain compensation costs.apportionment rates.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
Changes during the nine months ended September 30, 2017 forThe registrants had no unrecognized tax benefits were as follows:
 Mississippi Power Southern Power Southern Company
 (in millions)
Unrecognized tax benefits as of December 31, 2016$465
 $17
 $484
Tax positions from current periods2
 —
 9
Tax positions from prior periods(175) (17) (186)
Reductions due to settlements(290) —
 (290)
Balance as of September 30, 2017$2
 $—
 $17

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

The tax positions from current and prior periods primarily relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC, as well as federal income tax benefits from deferred ITCs. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
The impact on the effective tax rate, if recognized, is as follows:
 As of September 30, 2017 As of December 31, 2016
 Mississippi Power Southern Company Southern Company
 (in millions)
Tax positions impacting the effective tax rate$2
 $17
 $20
Tax positions not impacting the effective tax rate—
 —
 464
Balance of unrecognized tax benefits$2
 $17
 $484
The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information.
Accrued interest for all tax positions was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.
September 30, 2018. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016.2016, as well as the pre-Merger Southern Company Gas tax returns. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. 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.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165 in the year an abandonment is determined. The ultimate outcome of this matter cannot be determined at this time.2012.
(H)(I)DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign

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

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

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

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 (C)(D) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively.
The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A) under "Recently Adopted Accounting Standards – Other" for additional information.
Energy-Related Derivatives
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC extended theapproved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement.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-tradedNon-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.operating revenues.

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

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

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

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 September 30, 2017,2018, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
(in millions) (in millions) 
Southern Company(*)
463 2021 2024595 2022 2029
Alabama Power66 2020 —82 2022 —
Georgia Power159 2021 —165 2022 —
Gulf Power28 2020 —9 2020 —
Mississippi Power44 2021 —69 2022 —
Southern Power13 2018 —15 2020 —
Southern Company Gas(*)
153 2020 2024255 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 3.34.3 billion mmBtu and short natural gas positions of 3.14 billion mmBtu as of September 30, 2017,2018, which is also included in Southern Company's total volume.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 3413 million mmBtu for Southern Company, 112 million mmbtummBtu for Alabama Power, 4 million mmBtu for Georgia Power, and Southern Power, 5 million mmbtu for Alabama Power, 31 million mmBtu for Gulf Power, 2 million mmBtu for Mississippi Power, and 4 million mmBtu for MississippiSouthern Power.
For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 20182019 are $5 million for Southern Power and immaterial for all other 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

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

ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses isare recorded in OCI and isare reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings.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 providing an offset, with any difference representing ineffectiveness.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 September 30, 2017,2018, the following interest rate derivatives were outstanding:
Notional
Amount
 
Interest
Rate
Received
Weighted
Average
Interest
Rate Paid
Hedge
Maturity
Date
 Fair Value Gain (Loss) at September 30, 2017
Notional
Amount
 
Interest
Rate
Received
Weighted
Average
Interest
Rate Paid
Hedge
Maturity
Date
 Fair Value Gain (Loss) at September 30, 2018
(in millions)   (in millions)(in millions)   (in millions)
Cash Flow Hedges of Existing Debt  
Mississippi Power$900
 1-month
LIBOR 		0.79%March 2018 $2
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 —
$300
 2.75%3-month
LIBOR + 0.92%		June 2020 $(6)
Southern Company(*)
1,500
 2.35%1-month
LIBOR + 0.87%		July 2021 (19)1,500
 2.35%1-month
LIBOR + 0.87%		July 2021 (60)
Georgia Power250
 5.40%3-month
LIBOR + 4.02%		June 2018 —
500
 1.95%3-month
LIBOR + 0.76%		December 2018 (3)
Georgia Power500
 1.95%3-month
LIBOR + 0.76%		December 2018 (2)200
 4.25%3-month
LIBOR + 2.46%		December 2019 (3)
Georgia Power200
 4.25%3-month
LIBOR + 2.46%		December 2019 —
Southern Company Consolidated$3,650
 $(19)$2,500
 $(72)
(*)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 September 30, 20182019 are $(19) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses expected to be amortized into earnings through 2046.
Foreign Currency Derivatives
Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses isare recorded in OCI and isare reclassified into earnings at the same time thatand on the same income statement line as the earnings effect of the hedged transactions, affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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

At September 30, 2017,2018, the following foreign currency derivatives were outstanding:

Pay NotionalPay RateReceive NotionalReceive RateHedge
Maturity Date		Fair Value Gain (Loss) at September 30, 2017Pay NotionalPay RateReceive NotionalReceive RateHedge
Maturity Date		Fair Value Gain (Loss) at September 30, 2018

(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$42
$677
2.95%€600
1.00%June 2022$48
Southern Power564
3.78%500
1.85%June 202638
564
3.78%500
1.85%June 202651
Total$1,241
 €1,100
 $80
$1,241
 €1,100
 $99
The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 20182019 are $(23) million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

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

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
As of September 30, 2017As of December 31, 2016As of September 30, 2018As of December 31, 2017
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$21
$25
$73
$27
$15
$17
$10
$43
Other deferred charges and assets/Other deferred credits and liabilities13
23
25
33
5
26
7
24
Assets held for sale, current/Liabilities held for sale, current—
6
—
—
Assets held for sale/Liabilities held for sale—
2
—
—
Total derivatives designated as hedging instruments for regulatory purposes$34
$48
$98
$60
$20
$51
$17
$67
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Energy-related derivatives:  
Other current assets/Other current liabilities$8
$6
$23
$7
$3
$6
$3
$14
Other deferred charges and assets/Other deferred credits and liabilities1
1
—
—
Interest rate derivatives:  
Other current assets/Other current liabilities5
1
12
1
—
22
1
4
Other deferred charges and assets/Other deferred credits and liabilities—
23
1
28
—
50
—
34
Foreign currency derivatives:  
Other current assets/Other current liabilities—
23
—
25
—
23
—
23
Other deferred charges and assets/Other deferred credits and liabilities103
—
—
33
122
—
129
—
Total derivatives designated as hedging instruments in cash flow and fair value hedges$116
$53
$36
$94
$126
$102
$133
$75
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Other current assets/Other current liabilities$271
$254
$489
$483
$263
$317
$380
$437
Other deferred charges and assets/Other deferred credits and liabilities115
103
66
81
134
198
170
215
Interest rate derivatives: 
Other current assets/Other current liabilities—
—
1
—
Total derivatives not designated as hedging instruments$386
$357
$556
$564
$397
$515
$550
$652
Gross amounts recognized$536
$458
$690
$718
$543
$668
$700
$794
Gross amounts offset(*)
$(275)$(351)$(462)$(524)
Net amounts recognized in the Balance Sheets$261
$107
$228
$194
Gross amounts offset(a)
$(303)$(491)$(405)$(598)
Net amounts recognized in the Balance Sheets(b)
$240
$177
$295
$196
 

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

As of September 30, 2017As of December 31, 2016As of September 30, 2018As of December 31, 2017
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
$4
$13
$5
$5
$4
$2
$6
Other deferred charges and assets/Other deferred credits and liabilities3
3
7
4
2
6
2
4
Total derivatives designated as hedging instruments for regulatory purposes$9
$7
$20
$9
$7
$10
$4
$10
Gross amounts recognized$9
$7
$20
$9
$7
$10
$4
$10
Gross amounts offset$(5)$(5)$(8)$(8)$(4)$(4)$(4)$(4)
Net amounts recognized in the Balance Sheets$4
$2
$12
$1
$3
$6
$—
$6
  
Georgia Power  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Other current liabilities$10
$3
$30
$1
$5
$9
$2
$9
Other deferred charges and assets/Other deferred credits and liabilities8
8
14
7
2
13
4
10
Total derivatives designated as hedging instruments for regulatory purposes$18
$11
$44
$8
$7
$22
$6
$19
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Interest rate derivatives:  
Other current assets/Other current liabilities$1
$1
$2
$—
$—
$5
$—
$4
Other deferred charges and assets/Other deferred credits and liabilities—
2
—
3
—
1
—
1
Total derivatives designated as hedging instruments in cash flow and fair value hedges$1
$3
$2
$3
$—
$6
$—
$5
Gross amounts recognized$19
$14
$46
$11
$7
$28
$6
$24
Gross amounts offset$(10)$(10)$(8)$(8)$(7)$(7)$(6)$(6)
Net amounts recognized in the Balance Sheets$9
$4
$38
$3
$—
$21
$—
$18
  
Gulf Power  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Other current liabilities$—
$13
$4
$12
$—
$6
$—
$14
Other deferred charges and assets/Other deferred credits and liabilities—
9
1
17
—
2
—
7
Total derivatives designated as hedging instruments for regulatory purposes$—
$22
$5
$29
$—
$8
$—
$21
Gross amounts recognized$—
$22
$5
$29
$—
$8
$—
$21
Gross amounts offset$—
$—
$(4)$(4)
Net amounts recognized in the Balance Sheets$—
$22
$1
$25
$—
$8
$—
$21
 

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

As of September 30, 2017As of December 31, 2016As of September 30, 2018As of December 31, 2017
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$1
$4
$2
$6
$2
$3
$1
$6
Other deferred charges and assets/Other deferred credits and liabilities2
3
2
5
1
6
1
3
Total derivatives designated as hedging instruments for regulatory purposes$3
$7
$4
$11
$3
$9
$2
$9
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Interest rate derivatives:  
Other current assets/Other current liabilities$2
$—
$2
$—
$—
$—
$1
$—
Other deferred charges and assets/Other deferred credits and liabilities—
—
1
—
Total derivatives designated as hedging instruments in cash flow and fair value hedges$2
$—
$3
$—
$—
$—
$1
$—
Gross amounts recognized$5
$7
$7
$11
$3
$9
$3
$9
Gross amounts offset$(3)$(3)$(3)$(3)$(3)$(3)$(2)$(2)
Net amounts recognized in the Balance Sheets$2
$4
$4
$8
$—
$6
$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$8
$4
$18
$4
$2
$6
$3
$11
Other deferred charges and assets/Other deferred credits and liabilities1
1
—
—
Foreign currency derivatives:  
Other current assets/Other current liabilities—
23
—
25
—
23
—
23
Other deferred charges and assets/Other deferred credits and liabilities103
—
—
33
122
—
129
—
Total derivatives designated as hedging instruments in cash flow and fair value hedges$111
$27
$18
$62
$125
$30
$132
$34
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Other current assets/Other current liabilities$1
$—
$3
$1
$—
$—
$—
$2
Interest rate derivatives: 
Other current assets/Other current liabilities—
—
1
—
Total derivatives not designated as hedging instruments$1
$—
$4
$1
Gross amounts recognized$112
$27
$22
$63
$125
$30
$132
$36
Gross amounts offset$(1)$(1)$(5)$(5)$(2)$(2)$(3)$(3)
Net amounts recognized in the Balance Sheets$111
$26
$17
$58
$123
$28
$129
$33
 

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

As of September 30, 2017As of December 31, 2016As of September 30, 2018As of December 31, 2017
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$4
$1
$24
$3
$3
$1
$5
$8
Other deferred charges and assets/Other deferred credits and liabilities—
—
1
—
—
1
—
—
Total derivatives designated as hedging instruments for regulatory purposes$4
$1
$25
$3
$3
$2
$5
$8
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Energy-related derivatives:  
Assets from risk management activities/Liabilities from risk management activities-current$—
$2
$4
$3
$1
$—
$—
$3
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Assets from risk management activities/Liabilities from risk management activities-current$270
$254
$486
$482
$262
$316
$379
$434
Other deferred charges and assets/Other deferred credits and liabilities115
103
66
81
134
198
170
215
Total derivatives not designated as hedging instruments$385
$357
$552
$563
$396
$514
$549
$649
Gross amounts of recognized$389
$360
$581
$569
$400
$516
$554
$660
Gross amounts offset(*)
$(251)$(327)$(435)$(497)
Net amounts recognized in the Balance Sheets$138
$33
$146
$72
Gross amounts offset(a)
$(287)$(475)$(390)$(583)
Net amounts recognized in the Balance Sheets(b)
$113
$41
$164
$77
(*)(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76$189 million and $62$193 million as of September 30, 20172018 and December 31, 2016,2017, respectively.
(b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $5 million and $11 million as of September 30, 2018 and December 31, 2017, respectively.

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

At September 30, 20172018 and December 31, 2016,2017, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2017
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2018Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2018
Derivative Category and Balance Sheet
Location
Southern
Company(b)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(c)
Southern
Company(*)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(*)
(in millions) (in millions)
Energy-related derivatives:  
Other regulatory assets, current$(18)$(1)$—
$(13)$(3)$(1)$(9)$(2)$(4)$(6)$(2)$(1)
Other regulatory assets, deferred(12)(1)(1)(9)(1)—
(20)(4)(11)(2)(5)—
Other regulatory liabilities, current(a)
14
3
7
—
—
4
Other regulatory liabilities, deferred(b)
2
1
1
—
—
—
Assets held for sale, current(6)—
—
—
—
—
Assets held for sale(2)—
—
—
—
—
Other regulatory liabilities, current8
3
—
—
—
5
Total energy-related derivative gains (losses)$(14)$2
$7
$(22)$(4)$3
$(29)$(3)$(15)$(8)$(7)$4
(a)Georgia Power includes other regulatory liabilities, current in other current liabilities.
(b)Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
(c)(*)Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1$3 million at September 30, 2017.2018.
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Derivative Category and Balance Sheet
Location
Southern
Company(c)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(c)
Southern
Company(*)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(*)
(in millions) (in millions)
Energy-related derivatives:  
Other regulatory assets, current$(16)$(1)$—
$(9)$(5)$(1)$(34)$(4)$(7)$(14)$(5)$(4)
Other regulatory assets, deferred(19)—
—
(16)(3)—
(18)(3)(6)(7)(2)—
Other regulatory liabilities, current(a)
56
8
29
1
1
17
7
—
—
—
—
7
Other regulatory liabilities, deferred(b)
12
4
7
—
—
1
1
1
—
—
—
—
Total energy-related derivative gains (losses)$33
$11
$36
$(24)$(7)$17
$(44)$(6)$(13)$(21)$(7)$3
(a)Georgia Power includes other regulatory liabilities, current in other current liabilities.
(b)Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
(c)(*)Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8$6 million at December 31, 2016.2017.

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

For the three and nine months ended September 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
Gain (Loss) Recognized in OCI on DerivativeFor the Three Months
Ended September 30,		For the Nine Months
Ended September 30,
2018201720182017
 (in millions)(in millions)
Southern Company    
Energy-related derivatives$(5)$(6)$7
$(26)
Interest rate derivatives—
(1)(2)(2)
Foreign currency derivatives(10)46
(31)114
Total$(15)$39
$(26)$86
Southern Power    
Energy-related derivatives$(5)$(6)$5
$(21)
Foreign currency derivatives(10)46
(31)114
Total$(15)$40
$(26)$93
Southern Company Gas    
Energy-related derivatives$—
$—
$2
$(4)
For the three and 2016,nine months ended September 30, 2018 and 2017, the pre-tax effects of energy-related derivatives and interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on accumulated OCI were as follows:immaterial for the other registrants.
For the three and nine months ended September 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.
Derivatives in Cash Flow
Hedging Relationships
Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)
 
Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
 Statements of Income LocationAmount
 2017 2016  2017 2016
 (in millions)  (in millions)
Southern Company        
Energy-related derivatives$(6) $—
 Depreciation and amortization$(6) $1
Interest rate derivatives(1) (6) Interest expense, net of amounts capitalized(5) (6)
Foreign currency derivatives46
 37
 Interest expense, net of amounts capitalized(5) (6)
     
Other income (expense), net(*)
43
 7
Total$39
 $31
  $27
 $(4)
Alabama Power        
Interest rate derivatives$—
 $—
 Interest expense, net of amounts capitalized$(2) $(2)
Georgia Power        
Interest rate derivatives$—
 $—
 Interest expense, net of amounts capitalized$(1) $(1)
Mississippi Power        
Interest rate derivatives$(1) $(1) Interest expense, net of amounts capitalized$—
 $—
Southern Power        
Energy-related derivatives$(6) $—
 Depreciation and amortization$(6) $1
Foreign currency derivatives46
 37
 Interest expense, net of amounts capitalized(5) (6)
     
Other income (expense), net(*)
43
 7
Total$40
 $37
  $32
 $2
Southern Company Gas        
Interest rate derivatives$—
 $(5) Interest expense, net of amounts capitalized$—
 $—
(*)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.

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

For the three and nine months ended September 30, 20172018 and 2016,2017, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instrumentsand 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 September 30,		For the Nine Months
Ended September 30,
 
 2018201720182017
  (in millions)(in millions)
 Southern Company    
 Cost of natural gas$104
$134
$1,053
$1,085
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives—
—
(2)—
 Depreciation and amortization787
767
2,338
2,236
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives—
(6)2
(12)
 Interest expense, net of amounts capitalized(458)(407)(1,386)(1,248)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives(5)(5)(16)(15)
 Foreign currency derivatives(6)(5)(18)(17)
 
Gain (loss) on fair value hedges(b)
    
 Interest rate derivatives(4)(5)(35)(6)
 Other income (expense), net57
65
195
165
 
Gain (loss) on cash flow hedges(a)(c)
    
 Foreign currency derivatives(9)43
(46)139
 Alabama Power    
 Interest expense, net of amounts capitalized$(82)$(76)$(240)$(229)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives(1)(2)(4)(5)
 Georgia Power    
 Interest expense, net of amounts capitalized$(95)$(105)$(303)$(310)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives(1)(1)(4)(3)
 
Gain (loss) on fair value hedges(b)
    
 Interest rate derivatives—
—
(1)(1)
 Mississippi Power    
 Interest expense, net of amounts capitalized$(19)$13
$(59)$(23)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives—
—
(1)(1)
      

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

Derivatives in Cash Flow
Hedging Relationships		Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)		 Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
 Statements of Income LocationAmount
 2017 2016  2017 2016
 (in millions)  (in millions)
Southern Company        
Energy-related derivatives$(26) $(1) Depreciation and amortization$(12) $1
Interest rate derivatives(2) (189) Interest expense, net of amounts capitalized(15) (13)
Foreign currency derivatives114
 (1) Interest expense, net of amounts capitalized(17) (7)
     
Other income (expense), net(*)
139
 (13)
Total$86
 $(191)  $95
 $(32)
Alabama Power        
Interest rate derivatives$—
 $(3) Interest expense, net of amounts capitalized$(5) $(5)
Georgia Power        
Interest rate derivatives$—
 $—
 Interest expense, net of amounts capitalized$(3) $(3)
Gulf Power        
Energy-related derivatives$(1) $—
 Depreciation and amortization$—
 $—
Interest rate derivatives(1) (7) Interest expense, net of amounts capitalized—
 —
Total$(2) $(7)  $—
 $—
Mississippi Power        
Interest rate derivatives$—
 $(1) Interest expense, net of amounts capitalized$(1) $(1)
Southern Power        
Energy-related derivatives$(21) $(1) Depreciation and amortization$(12) $1
Interest rate derivatives—
 —
 Interest expense, net of amounts capitalized—
 (1)
Foreign currency derivatives114
 (1) Interest expense, net of amounts capitalized(17) (7)
 

 

 
Other income (expense), net(*)
139
 (13)
Total$93
 $(2)  $110
 $(20)
 Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging RelationshipsFor the Three Months
Ended September 30,		For the Nine Months
Ended September 30,
 
 2018201720182017
  (in millions)(in millions)
 Southern Power    
 Depreciation and amortization$130
$131
$370
$379
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives—
(6)2
(12)
 Interest expense, net of amounts capitalized(45)(47)(138)(144)
 
Gain (loss) on cash flow hedges(a)
    
 Foreign currency derivatives(6)(5)(18)(17)
 Other income (expense), net17
3
22
3
 
Gain (loss) on cash flow hedges(a)(c)
    
 Foreign currency derivatives(9)43
(46)139
      
 Southern Company Gas    
 Cost of natural gas$104
$134
$1,053
$1,085
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives—
—
(2)—
(*)(a)Amounts reflect gains or losses on cash flow hedges that were reclassified from accumulated OCI into income.
(b)For fair value hedges presented above, generally changes in the fair value of the derivative contracts are equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
For Southern Company Gas, the pre-tax effect of energy related derivativesthree and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor nine months ended September 30, 2018 and 2017, the successor periodpre-tax effects of July 1, 2016 throughcash flow hedge accounting on income for interest rate derivatives were immaterial for Gulf Power and Southern Company Gas.
As of September 30, 2016,2018 and December 31, 2017, the predecessor period of January 1, 2016 through June 30, 2016following amounts were as follows:recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
 
Gain (Loss) Recognized in OCI on Derivative
(Effective Portion)
  Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging RelationshipsNine Months Ended September 30, 2017 Statements of Income LocationNine Months Ended September 30, 2017
 (in millions)  (in millions)
Energy-related derivatives$(4) Cost of natural gas$—

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 September 30, 2018As of December 31, 2017
As of September 30, 2018As of December 31, 2017

(in millions) (in millions)
Southern Company     
Securities due within one year$(499)$(746) $1
$3
Long-term debt(2,526)(2,553) 65
35
      
Georgia Power     
Securities due within one year$(499)$(746) $1
$3
Long-term debt(497)(498) 2
1

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

 Gain (Loss) Recognized in OCI on Derivative (Effective Portion)  Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
 Successor  Predecessor  Successor  Predecessor
Derivatives in Cash Flow Hedging Relationships
July 1, 2016
through
September 30, 2016
  January 1, 2016 through June 30, 2016 Statements of Income LocationJuly 1, 2016
through
September 30, 2016		  January 1, 2016 through June 30, 2016
 (in millions)  (in millions)  (in millions)  (in millions)
Energy-related derivatives$—
  $—
 Cost of natural gas$—
  $(1)
Interest rate derivatives(5)  (64) Interest expense, net of amounts capitalized—
  —
Total$(5)  $(64)  $—
  $(1)
For the three and nine months ended September 30, 20172018 and 2016,2017, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.
For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate 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 September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended
September 30,
Derivatives in Non-Designated Hedging RelationshipsStatements of Income Location20172016 20172016Statements of Income Location20182017 20182017
 (in millions) (in millions) (in millions) (in millions)
Southern Company    
Energy Related derivatives:
Natural gas revenues(*)
$(17)$—
 $48
$—
Energy-related derivatives:
Natural gas revenues(*)
$(36)$(17) $(79)$48
Cost of natural gas2
6
 (2)6
Cost of natural gas2
2
 5
(2)
Total derivatives in non-designated hedging relationshipsTotal derivatives in non-designated hedging relationships$(15)$6
 $46
$6
Total derivatives in non-designated hedging relationships$(34)$(15) $(74)$46
(*)Excludes gains (losses) recorded in cost of natural gas revenues associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.
  Gain (Loss)
  Successor
Successor Successor Successor  Predecessor
Derivatives in Non-Designated Hedging RelationshipsStatements of Income LocationThree Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 July 1, 2016 through September 30, 2016  January 1, 2016 through June 30, 2016
  (in millions) (in millions) (in millions) (in millions)   
Southern Company Gas          
Energy Related derivatives:
Natural gas revenues(*)
$(17) $—
 $48
 $—
  $(1)
 Cost of natural gas2
 6
 (2) 6
  (62)
Total derivatives in non-designated hedging relationships$(15) $6
 $46
 $6
  $(63)
(*)Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

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

For the three and nine months ended September 30, 20172018 and 2016,2017, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial forfor the traditional electric operating companies and Southern Power.
For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
Derivatives in Fair Value Hedging Relationships
  Gain (Loss)
  Three Months Ended September 30,Nine Months Ended September 30,
Derivative CategoryStatements of Income Location2017 20162017 2016
  (in millions)(in millions)
Southern Company       
Interest rate derivatives:Interest expense, net of amounts capitalized$(5) $(9)$(6) $15
Georgia Power       
Interest rate derivatives:Interest expense, net of amounts capitalized$—
 $(5)$(1) $10
For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
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 September 30, 2017,2018, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
AtFor the registrants with interest rate derivatives at September 30, 2017,2018, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial for all registrants. Theimmaterial. At September 30, 2018, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2017,2018, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2017,2018, cash collateral held on deposit in broker margin accounts was $76$189 million.

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

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern

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

Company, the traditional electric operating companies, Southern Power, and Southern Company Gas only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

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

(I)(J)ACQUISITIONS AND DISPOSITIONS
Southern CompanyCompany's Sale of Gulf Power
Merger withOn May 20, 2018, Southern Company Gas
Southern Company Gas isentered into a stock purchase agreement (Gulf Power SPA) with NextEra Energy and its wholly-owned subsidiary 700 Universe, LLC, which provides for the sale of all of the capital stock of Gulf Power for an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a totalaggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $8.0 billion$1.3 billion), subject to (i) customary adjustments for indebtedness and Southern Company Gas becameworking capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a wholly-owned, direct subsidiary of Southern Company.specified capital expenditure target.
The Merger was accounted for using the acquisition method of accounting with the assets acquiredGulf Power SPA contains customary representations, warranties, and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
Southern Company Gas Purchase Price 
 (in millions)
Current assets$1,557
Property, plant, and equipment10,108
Goodwill5,967
Intangible assets400
Regulatory assets1,118
Other assets229
Current liabilities(2,201)
Other liabilities(4,742)
Long-term debt(4,261)
Noncontrolling interest(174)
Total purchase price$8,001
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $565 million and $2.8 billion and net income of $15 million and $303 million for the three and nine months ended September 30, 2017, respectively, and operating revenues and net income of $543 million and $4 million, respectively, for the three months ended September 30, 2016.
The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisitioncovenants of Southern Company, Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement700 Universe, LLC, and NextEra Energy. These covenants include, among others, an obligation of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fundcause Gulf Power to operate its business in the Merger,ordinary course until the sale is consummated and (iv) the elimination of nonrecurring expenses associated with the Merger.

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

 For the Nine Months Ended September 30,
 2016
Operating revenues (in millions)
$16,609
Net income attributable to Southern Company (in millions)
$2,394
Basic Earnings Per Share (EPS)$2.52
Diluted EPS$2.51
These unaudited pro forma results arean obligation for comparative purposes only and may not be indicativeeach of the results that would have occurred had this acquisition been completed on January 1, 2015parties 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) approval by the results that wouldFERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iii) other customary closing conditions.
The Gulf Power SPA may be attained in the future.
Acquisition of PowerSecure
On May 9, 2016,terminated by either Southern Company acquiredor 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 outstanding stockconditions 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 PowerSecure,$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 providertermination fee of products and services$100 million.
The sale of Gulf Power is expected to occur in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
first quarter 2019. The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair valueof Gulf Power are classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of the acquisition date.September 30, 2018. See "Assets Held for Sale" below for additional information. The following table presents the final purchase price allocation:ultimate outcome of this matter cannot be determined at this time.
PowerSecure Purchase Price 
 (in millions)
Current assets$172
Property, plant, and equipment46
Intangible assets106
Goodwill284
Other assets4
Current liabilities(121)
Long-term debt, including current portion(48)
Deferred credits and other liabilities(14)
Total purchase price$429
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.

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

Southern Power
See Note 211 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 Nine Months Ended September 30, 20172018
During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy,2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the project discussed below.Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material.
Project FacilityResourceSeller; Acquisition Date
Approximate Nameplate Capacity (MW)
LocationSouthern Power Percentage OwnershipActual CODPPA Contract Period
BethelWindInvenergy,
January 6, 2017		276Castro County, TX100% January 201712 years
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.

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

The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The BethelGaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalizedservice during the nine months ended September 30, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind.
Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.March 2018.
Construction Projects Completed and in Progress and/or Completed
During the nine months ended September 30, 2017, in accordance with its overall growth strategy,2018, Southern Power completed construction of and placed in service,started, continued, or continuedcompleted construction of the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP.table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360$575 million and $415$640 million for the Mankato, Wild Horse Mountain, and Cactus FlatsReading facilities. At September 30, 2018, construction costs included in CWIP related to these projects totaled $246 million. The ultimate outcome of these matters cannot be determined at this time.
Project FacilityResource
Approximate Nameplate Capacity (MW)
LocationActual/Expected CODPPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East PecosSolar120Pecos County, TXMarch 201715 years
LamesaSolar102Dawson County, TXApril 201715 years
Projects Under Construction as of September 30, 2017
Cactus Flats(*)(a)
Wind148Concho County, TXThird quarterJuly 201812-15 years
MankatoNatural Gas345385Mankato, MNSecondFirst half 201920 years
Wild Horse Mountain(b)
Wind100Pushmataha County, OKFourth quarter 201920 years
Reading(c)
Wind200Osage and Lyon Counties, KSSecond quarter 202012 years
(*)(a)OnIn July 31, 2017, Southern Power acquired apurchased 100% ownership interest inof the Cactus Flats facility which isand commenced construction. In July 2018, the facility was placed in service and, in August 2018, Southern Power closed on a tax equity partnership agreement and owns 100% of the early stages of construction, from RES America Developments, Inc.class B membership interests.

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

(b)In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.
(c)In August 2018, Southern Power purchased 100% of the membership interests from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.
Development Projects
In December 2016,During 2017, as part of Southern Power'sits renewable development strategy, oneSouthern 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 using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.
During 2016, Southern Power's wholly-owned subsidiariesPower entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. AlsoIn addition, in December 2016, Southern Power signed agreements and made payments to purchasepurchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. AllAny wind projects using this equipment and reaching commercial operation by the end of 2020 are expected to qualify for 100% PTCs.
In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of the wind turbine equipment was delivered by April 2017, which allowsto potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the third quarter 2018, as a result of a review of various options for probable dispositions of wind turbine equipment not already deployed to development or construction projects, to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. Southern Power recorded a $36 million asset impairment charge on the equipment.
The ultimate outcome of these matters cannot be determined at this time.
Sale of Solar Facility Interests
In May 2018, Southern Power sold a 33% equity interest in SPSH, a 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

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

$770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital. Since Southern Power retains control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction and Southern Power will continue to consolidate the results of SPSH. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $410 million decrease to Southern Power's common stockholder's equity.
Sale of Florida Plants
In May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants, for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments.
The sale is subject to certain closing and timing conditions and approvals, including, but not limited to, 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 sale is expected to occur in the first quarter 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018. The assets and liabilities of the Florida Plants are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of September 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.
Sale of Wind Facility Interests
On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Southern Power intends to use the proceeds to return capital of approximately $1.0 billion to Southern Company. The ultimate outcome of this matter cannot be determined at this time.
Sale of Mankato Plant
On November 5, 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 $650 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $66,667 per day for each day after June 1, 2019, if the expansion has not achieved commercial operation, but such decrease will not exceed $15 million. This transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.
Assets Subject to Lien
Under the terms of the PPA and the expansion PPA for the Mankato project, approximately $500 million of assets, primarily related to property, plant, and equipment, are subject to lien at September 30, 2018.
Southern Company Gas
Sale of Pivotal Home Solutions
On October 15, 2017,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 $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018. The after-tax

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

loss included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas provided certain administrative and operational services through November 4, 2018.
Sale of Elizabethtown Gas and Elkton Gas
On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements forcompleted the salesales 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. The completion of each sale isbillion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the satisfaction or waiverfourth quarter 2018. This disposition resulted in an estimated pre-tax gain of certain closing conditions, including, among others, (i)approximately $230 million and an after-tax gain of approximately $18 million, the expiration or terminationcalculations of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The saleswhich are expected to be finalized in the fourth 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. 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.
Sale of Florida City Gas
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed by the endstock 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, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth 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. 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.
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 September 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 third quarter 2018.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 ultimate outcomefollowing table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at September 30, 2018:
 Southern Company
Southern
Power
 (in millions)
Assets Held for Sale:  
Current assets$407
$18
Total property, plant, and equipment4,093
168
Other non-current assets574
17
Total Assets Held for Sale$5,074
$203
   
Liabilities Held for Sale:  
Current liabilities$355
$4
Long-term debt1,285
—
Accumulated deferred income taxes542
—
Other non-current liabilities1,008
—
Total Liabilities Held for Sale$3,190
$4
Southern Company, Southern Power, and Southern Company Gas 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.
Gulf Power and the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these matters cannot be determined at this time.components for the three and nine months ended September 30, 2018 and 2017 is presented below:
 For the Three Months
Ended September 30,		 For the Nine Months
Ended September 30,
20182017 20182017
 (in millions) (in millions)
Earnings before income taxes:     
Gulf Power$59
$103
 $146
$199
Southern Power's Florida Plants$18
$11
 $40
$28
(J)(K)JOINT OWNERSHIP AGREEMENTSVARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS
Southern Power
In May 2018, Southern Power sold a 33% limited partnership 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 September 30, 2018, SPSH had total assets of $6.4 billion, total liabilities of $111 million, and noncontrolling interests related to other partners' interests of $1.2 billion. Cash distributions from SPSH are allocated 67% to

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

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.

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

information on Southern Company Gas' equity method investments.
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of September 30, 20172018 and December 31, 20162017 and related income from those investments for the successor three and nine monthnine-month periods ended September 30, 2017, the successor three-month period ended2018 and September 30, 2016, and for the predecessor period January 1, 2016 through June 30, 20162017 were as follows:
Balance Sheet InformationSeptember 30, 2017December 31, 2016
Investment BalanceSeptember 30, 2018December 31, 2017
(in millions)(in millions)
SNG$1,385
$1,394
$1,260
$1,262
Atlantic Coast Pipeline61
33
73
41
PennEast Pipeline49
22
70
57
Triton43
44
Pivotal JAX LNG, LLC40
16
Horizon Pipeline30
30
Other1
2
126
117
Total$1,609
$1,541
$1,529
$1,477
SuccessorSuccessorSuccessorPredecessor
Income Statement InformationThree Months Ended September 30, 2017Three Months Ended September 30, 2016Nine Months Ended September 30, 2017January 1, 2016 through June 30, 2016
Earnings from Equity
Method Investments
Three Months Ended
September 30, 2018		Three Months Ended
September 30, 2017		Nine Months Ended
September 30, 2018		Nine Months
Ended
September 30, 2017
(in millions)(in millions)(in millions)
SNG$28
$27
$86
$—
$29
$28
$95
$86
PennEast Pipeline1
—
5
—
2
1
4
5
Atlantic Coast Pipeline1
1
4
—
1
1
4
4
Triton1
1
3
1
Horizon Pipeline1
—
2
1
Other2
2
5
5
Total$32
$29
$100
$2
$34
$32
$108
$100
Southern Natural Gas
In September 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the three and nine months ended September 30, 20172018 and for the period September 1, 2016 through September 30, 20162017 is as follows:
Income Statement InformationThree Months Ended September 30, 2017Nine Months Ended September 30, 2017September 1, 2016 through September 30, 2016
Three Months Ended
September 30, 2018
Three Months Ended
September 30, 2017
Nine Months Ended
September 30, 2018
Nine Months
Ended
September 30, 2017
(in millions)(in millions)
Revenues$146
$445
$82
$145
$146
$451
$445
Operating income$71
$218
$60
$71
$71
$230
$218
Net income$57
$172
$55
$58
$57
$190
$172

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

(K)(L) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the sevenits natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. See Note (J) under "Southern Company Gas" for additional information.
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $134 million and $326 million for the three and nine months ended September 30, 2018, respectively, and $105 million and $295 million for the three and nine months ended September 30, 2017, respectively, and $110respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $14 million and $313$22 million for the three and nine months ended September 30, 2016,2018, respectively, and $9 million and $19 million for the three and nine months ended September 30, 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $38 million and $96 million for the three and nine months ended September 30, 2018, respectively, and $38 million and $94 million for the three and nine months ended September 30, 2017, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

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

Financial data for business segments and products and services for the three and nine months ended September 30, 20172018 and 20162017 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 September 30, 2018:Three Months Ended September 30, 2018: 
Operating revenues$5,014
$635
$(140)$5,509
$492
$202
$(44)$6,159
Segment net income (loss)(a)(b)(c)(d)
1,148
92
—
1,240
46
(119)(3)1,164
Nine Months Ended September 30, 2018:Nine Months Ended September 30, 2018: 

 
Operating revenues$13,117
$1,699
$(360)$14,456
$2,861
$984
$(143)$18,158
Segment net income (loss)(c)(d)
1,711
235
—
1,946
294
(292)—
1,948
At September 30, 2018: 
Goodwill$—
$2
$—
$2
$5,015
$298
$—
$5,315
Total assets75,069
15,355
(322)90,102
20,398
3,086
(1,869)111,717
Three Months Ended
September 30, 2017:		 Three Months Ended September 30, 2017: 
Operating revenues$5,017
$618
$(112)$5,523
$565
$153
$(40)$6,201
$5,017
$618
$(112)$5,523
$565
$153
$(40)$6,201
Segment net income (loss)(a)(b)
1,008
124
—
1,132
15
(80)2
1,069
1,008
124
—
1,132
15
(80)2
1,069
Nine Months Ended
September 30, 2017:		 

 Nine Months Ended September 30, 2017: 
Operating revenues$12,960
$1,597
$(318)$14,239
$2,841
$442
$(119)$17,403
$12,960
$1,597
$(318)$14,239
$2,841
$442
$(119)$17,403
Segment net income (loss)(c)(d)
—
276
—
276
303
(232)—
347
Total assets at September 30, 2017$73,056
$14,648
$(322)$87,382
$22,190
$2,275
$(1,532)$110,315
Three Months Ended
September 30, 2016:		 
Operating revenues$5,236
$500
$(117)$5,619
$543
$139
$(37)$6,264
Segment net income (loss)(a)(b)
1,022
176
—
1,198
4
(62)(1)1,139
Nine Months Ended
September 30, 2016:		 
Operating revenues$13,120
$1,189
$(330)$13,979
$543
$311
$(118)$14,715
Segment net income (loss)(a)(b)
2,086
315
—
2,401
4
(146)(8)2,251
Total assets at December 31, 2016$72,141
$15,169
$(316)$86,994
$21,853
$2,474
$(1,624)$109,697
Segment net income (loss)(a)(b)(e)
—
276
—
276
303
(232)—
347
At December 31, 2017: 
Goodwill$—
$2
$—
$2
$5,967
$299
$—
$6,268
Total assets72,204
15,206
(325)87,085
22,987
2,552
(1,619)111,005
(a)Attributable to Southern Company.
(b)
Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCCplants under construction of $34$1 million ($211 million after tax) and $88$34 million ($5421 million after tax) for the three months ended September 30, 2018 and 2017, respectively, and 2016, respectively,$1.1 billion ($0.8 billion after tax) and $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) for the nine months ended September 30, 20172018 and 2016,2017, respectively. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined CycleNuclear Construction – " and "Kemper IGCC Schedule and Cost EstimateCounty Energy Facility" for additional information.
(c)
Segment net income (loss) for Southern Power includes pre-tax impairment charges of $36 million ($27 million after tax) and $155 million ($116 million after tax) for the three and nine months ended September 30, 2018, respectively. See Note (J) under "Southern Power – Development Projects" and " – Sale of Florida Plants" for additional information.
(d)
Segment net income (loss) for Southern Company Gas includes a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax) for the three and nine months ended September 30, 2018, respectively, related to the Southern Company Gas Dispositions and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.
(e)Segment net income (loss) for the traditional electric operating companies also 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 nine months ended September 30, 2017. See Note (B)3 to the financial statements of Southern Company under "Regulatory"Regulatory Matters – Gulf Power – Retail Base Rate Cases"Cases" in Item 8 of the Form 10-K for additional information.

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

Products and Services
  Electric Utilities' Revenues
Period Retail Wholesale Other Total
  (in millions)
Three Months Ended September 30, 2017 $4,615
 $718
 $190
 $5,523
Three Months Ended September 30, 2016 4,808
 613
 198
 5,619
         
Nine Months Ended September 30, 2017 $11,786
 $1,867
 $586
 $14,239
Nine Months Ended September 30, 2016 11,932
 1,455
 592
 13,979

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

 Electric Utilities' Revenues
PeriodRetailWholesaleOtherTotal
 (in millions)
Three Months Ended September 30, 2018$4,605
$693
$211
$5,509
Three Months Ended September 30, 20174,615
718
190
5,523
     
Nine Months Ended September 30, 2018$11,913
$1,923
$620
$14,456
Nine Months Ended September 30, 201711,786
1,867
586
14,239
Southern Company Gas' RevenuesSouthern Company Gas' Revenues
PeriodGas
Distribution
Operations		Gas
Marketing
Services		OtherTotalGas
Distribution
Operations		Gas
Marketing
Services		OtherTotal
(in millions)(in millions)
Three Months Ended September 30, 2018$438
$44
$10
$492
Three Months Ended September 30, 2017$430
$143
$(8)$565
430
143
(8)565
Nine Months Ended September 30, 2018$2,276
$403
$182
$2,861
Nine Months Ended September 30, 2017$2,119
$597
$125
$2,841
2,119
597
125
2,841
Three and Nine Months Ended September 30, 2016$420
$126
$(3)$543
Southern Company Gas
Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. The non-reportable segments are combined and presented as all other.
Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in seven states. In July 2018, Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note (J) under "Southern Company Gas" for additional information.
Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. On June 4, 2018, Southern Company Gas sold Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.
Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.
Gas midstream operations primarily consists of Southern Company Gas' pipeline investments, with storage and fuel operations also aggregated into this segment.
The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure.
After the Merger, Southern Company Gas changed its segment performance measure to net income. In order to properly assess net income by segment, Southern Company Gas executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor period, Southern Company Gas is unable to provide the comparable net income.
Business segment financial data for the successor three months ended September 30, 2017 and 2016, the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 was as follows:
 Gas Distribution OperationsGas Marketing Services
Wholesale Gas Services(*)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidated
 (in millions)
Successor – Three Months Ended September 30, 2017:      
Operating revenues$472
$143
$(24)$16
$607
$2
$(44)$565
Segment net income52
1
(23)14
44
(29)—
15
Successor – Nine Months Ended September 30, 2017:      
Operating revenues$2,255
$597
$95
$53
$3,000
$7
$(166)$2,841
Segment net income223
36
28
38
325
(22)—
303
Successor – Total assets at
September 30, 2017		$18,711
$2,089
$893
$2,359
$24,052
$11,400
$(13,262)$22,190

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

Business segment financial data for the three and nine months ended September 30, 2018 and 2017 was as follows:
 Gas Distribution OperationsGas Marketing Services
Wholesale Gas Services(*)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidated
 (in millions)
Successor – Three Months Ended September 30, 2016:      
Operating revenues$455
$126
$(8)$13
$586
$2
$(45)$543
Segment net income (loss)27
(4)(11)14
26
(22)—
4
Predecessor – January 1, 2016 through June 30, 2016:      
Operating revenues$1,575
$435
$(32)$25
$2,003
$4
$(102)$1,905
Segment EBIT353
109
(68)(6)388
(60)—
328
Successor – Total assets at
December 31, 2016		$19,453
$2,084
$1,127
$2,211
$24,875
$11,145
$(14,167)$21,853
 
Gas Distribution Operations(a)(c)
Gas Marketing Services(b)(c)
Wholesale Gas Services(d)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidated
 (in millions)
Three Months Ended September 30, 2018:      
Operating revenues$441
$44
$(8)$20
$497
$1
$(6)$492
Segment net income (loss)74
(8)(18)16
64
(18)—
46
Nine Months Ended September 30, 2018:      
Operating revenues2,297
403
142
60
2,902
3
(44)2,861
Segment net income (loss)290
(71)65
54
338
(44)—
294
Total assets at September 30, 2018:16,850
1,522
855
2,297
21,524
10,146
(11,272)20,398
Three Months Ended September 30, 2017:      
Operating revenues$472
$143
$(24)$16
$607
$2
$(44)$565
Segment net income (loss)52
1
(23)14
44
(29)—
15
Nine Months Ended September 30, 2017:       
Operating revenues2,255
597
95
53
3,000
7
(166)2,841
Segment net income (loss)223
36
28
38
325
(22)—
303
Total assets at December 31, 2017:19,358
2,147
1,096
2,241
24,842
12,184
(14,039)22,987
(*)(a)
Operating revenues for the three gas distribution operations dispositions were $8 million and $50 million for the three months ended September 30, 2018 and 2017, respectively, and $245 million and $274 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.
(b)
Operating revenues for the gas marketing services disposition were $32 million for the three months ended September 30, 2017 and $55 million and $95 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.
(c)
Segment net income for gas distribution operations includes a gain on dispositions of $351 million ($38 million after tax) for the three and nine months ended September 30, 2018. Segment net income for gas marketing services includes a gain on disposition of $2 million ($2 million after tax) for the three months ended September 30, 2018 and a loss on disposition of $34 million ($73 million loss after tax) and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.
(d)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.
 Third Party Gross Revenues Intercompany Revenues Total Gross Revenues Less Gross Gas Costs Operating Revenues
 (in millions)
Successor – Three Months Ended September 30, 2017$1,411
 $103
 $1,514
 $1,538
 $(24)
Successor – Nine Months Ended September 30, 20174,781
 362
 5,143
 5,048
 95
Successor – Three Months Ended September 30, 20161,688
 77
 1,765
 1,773
 (8)
Predecessor – January 1, 2016 through June 30, 2016$2,500
 $143
 $2,643
 $2,675
 $(32)
 Third Party Gross RevenuesIntercompany RevenuesTotal Gross RevenuesLess Gross Gas CostsOperating Revenues
 (in millions)
Three Months Ended September 30, 2018$1,573
$82
$1,655
$1,663
$(8)
Three Months Ended September 30, 20171,411
103
1,514
1,538
(24)
Nine Months Ended September 30, 2018$4,847
$352
$5,199
$5,057
$142
Nine Months Ended September 30, 20174,781
362
5,143
5,048
95

Table of Contents

PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
Item 1A. Risk Factors.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
The bankruptcy filing of the EPC Contractor is expected to have a material impact onGeorgia Power may incur additional costs or delays in the construction cost and schedule of as well as the cost recovery for, Plant Vogtle Units 3 andor 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, and any inability or other failure by Toshiba to perform its obligations underPower.
Background
In 2009, the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to completeGeorgia PSC certified construction of Plant Vogtle Units 3 and 4,4. In 2012, the NRC issued the related combined construction and thereforeoperating 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 the financial statements of Southern Company and Georgia Power.
See "Construction Risk" in Item 1A – Risk Factors of Southern Company and Georgia Power in the Form 10-K for a discussion of risks relating to major construction projects, including Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
On4 Agreement, which was a substantially fixed price agreement. In March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4,
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreementthe Interim Assessment Agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.
to allow construction to continue. The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired onin July 27, 2017.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, 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, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017 of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.
The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).



On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
Additionally, on June 9, 2017,when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 20, 2017,Services Agreement. Under the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into theVogtle Services Agreement, (ii) assumeWestinghouse provides facility design and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts,engineering services, procurement and (iv) reject the Vogtle 3technical support, and 4 Agreement. The Services Agreement,staff augmentation on a time and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.materials cost basis.
EffectiveIn October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) withexecuted the Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement, is a cost reimbursable plus fee arrangement, whereby Bechtel will beis 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 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, 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 connection withDecember 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue with construction of Plant Vogtle Units 3 and 4, (described below),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 September 30, 2018(b)
(4.3)
Remaining estimate to complete(a)
$4.1
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.
The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted 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 did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 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 recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.
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 only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 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 Criteria (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 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 agreed on a term sheetentered into an amendment to amend the existingtheir joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 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).
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 above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 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, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.
If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction



costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.
In the event the actual costs at completion are less than the EAC reflected in the nineteenth VCM report and Plant Vogtle Unit 3 is placed in service by the currently scheduled date of November 2021 or Plant Vogtle Unit 4 is placed in service by the currently scheduled date of November 2022, Georgia Power would be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Vogtle Owners would be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.
Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.
Under the term sheet,Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, 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 eventsProject Adverse Events occur, includingincluding: (i) the bankruptcy of Toshiba or a material breach by Toshiba ofToshiba; (ii) the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the Bechtel Agreement;agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC 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 suchexcluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are deemed unreasonabledisallowed by the Georgia PSC for recovery, or imprudent; orfor which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an increase in the construction budget contained in the seventeenth Vogtle Construction Monitoring (VCM) report by more than $1 billion orincremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project schedule containedat any time in the seventeenth VCM report by more than one year. its sole discretion.
In addition, underpursuant to the term sheet,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, or Southern Nuclear.including the Bechtel Agreement.
The term sheet also confirmsVogtle Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Owners' sole recourse against Georgia Power or Southern NuclearUnits 3 and 4 would continue for any action or inactiona period of 30 days if the holders of more than 50% of the ownership interests vote in connection with their performance as agent forfavor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners is limited(i) would agree to removalnegotiate in



good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.
Purchase of PTCs During Commercial Operation
In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power and/or Southern Nuclearagreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as agent, except in cases of willful misconduct.
Indescribed below) at varying purchase prices dependent upon the seventeenth VCM report, Georgia Power recommended thatactual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be continued,at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.
Potential Funding to MEAG Project J
Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with Southern Nuclear serving as project manager.MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power believes thatwould purchase from MEAG SPVJ the most reasonable schedule for completingrights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion(approximately 206 MWs) at varying prices dependent upon the stage of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatmentconstruction of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment4. The aggregate purchase price of the PTCs, together with any advances made as described in Plant Vogtle Units 3 and 4; (ii) thatthe next paragraph, shall not exceed $300 million.
At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Cost Settlement Agreement remains in full force and effect, includingJoint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power retaining the burdenPower), subject to any required approvals of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC and the DOE.
In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will make no prudence findingnot sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Term Sheet as to its payment obligations and the other provisions of the Vogtle Joint Ownership Agreements.
Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantorform of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.



Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:
 (in billions)
Estimated cost to complete$4.2
CWIP as of September 30, 20174.6
Guarantee Obligations(1.7)
Estimated capital costs$7.1
Vogtle Cost Settlement Agreement Revised Forecast(5.7)
Estimated net additional capital costs$1.4
Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.
Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSCadvances, including in the event of a cancellation decision are as follows:
 Cancellation Cost Estimate
 (in billions)
CWIP as of September 30, 2017$4.6
Financing costs collected, net of tax1.5
Cancellation costs(*)
0.4
Guarantee Obligations(1.7)
Estimated net cancellation cost$4.8
(*)The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.
The Guarantee Obligations continuefailure to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by thereceive any required Georgia PSC are allowed recovery, including carrying costs,or DOE approvals, and cancel the project in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the statuslieu of construction and rate recovery.providing such funding.
The ultimate outcome of these matters 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 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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 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 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.
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.
  (3) Articles of Incorporation and By-Laws
Alabama Power
(b)1-
Articles of Amendment to the Articles of Incorporation of Alabama Power dated September 7, 2017. (Designated in Form 8-K dated September 5, 2017, File No. 1-3164, as Exhibit 4.5.)

(4) Instruments Describing Rights of Security Holders, Including Indentures
     
  Georgia PowerSouthern Company
     
 *(c)(a)1-
Fifty-EighthTwentieth Supplemental Indenture to Senior Note Indenture, dated as of August 8, 2017,17, 2018, providing for the issuance of the Series 2017C 2.00%2018A Floating Rate Senior Notes due September 8,February 14, 2020. (Designated in Form 8-K dated August 3, 2017, File No. 1-6468, as Exhibit 4.2.)
(c)2-
Subordinated Note Indenture, dated as of September 1, 2017, between Georgia Power and Wells Fargo Bank, National Association, as Trustee, and First Supplemental Indenture thereto dated as of September 21, 2017. (Designated in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.3 and in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.4.)
(c)3-
Amendment No. 3, dated July 27, 2017 to Loan Guarantee Agreement dated February 20, 2014, between Georgia Power and the DOE. (Designated in Form 8-K dated July 27, 2017, File No. 1-6468, as Exhibit 4.1.)
(10) Material Contracts
Mississippi Power
(e)1-
Promissory Note dated September 15, 2017, between Mississippi Power and Southern Company in the aggregate principal amount of up to $150,000,000. (Designated in Form 8-K dated September 15, 2017, File No. 001-11229, as Exhibit 10.1.)
     
  Southern Company Gas
     
 *(g)1-
Asset PurchaseSupplemental Indenture dated August 3, 2018 of Northern Illinois Gas Company to The Bank of New York Mellon Trust Company, N.A., under Indenture dated January 1, 1954.

Table of Contents

(10) Material Contracts
Georgia Power
(c)1-
First Amendment to Agreement Regarding Additional Participating Party Rights and Amendment No. 3 to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of October 15, 2017, byAugust 31, 2018, among Georgia Power, Oglethorpe Power Corporation, MEAG, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and between Pivotal Utility Holdings, Inc., as Seller, and South Jersey Industries, Inc., as Buyer.The City of Dalton, Georgia. (Designated in Form 8-K dated October 15, 2017,August 31, 2018, File No. 1-14174,1-6468 as Exhibit 10.1.)
     
  (24) Power of Attorney and Resolutions
     
  Southern Company
     
  (a)1-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016,2017, File No. 1-3526 as Exhibit 24(a).)
(a)2-
Power of Attorney for Andrew W. Evans. (Designated in Form 10-Q for the quarter ended June 30, 2018, File No. 1-3526 as Exhibit 24(a)2.)
     
  Alabama Power
     
  (b)-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016,2017, File No. 1-3164 as Exhibit 24(b).)
     
  Georgia Power
     
  (c)1-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016,2017, File No. 1-6468 as Exhibit 24(c).)
*(c)2-
Power of Attorney for Xia Liu.
     
  Gulf Power
     
  (d)1-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016,2017, File No. 001-31737 as Exhibit 24(d).)
*(d)2-
Power of Attorney for Robin B. Boren.
     
  Mississippi Power
     
  (e)-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016,2017, File No. 001-11229 as Exhibit 24(e).)
     

  Southern Power
     
  (f)1-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016,2017, File No. 001-37803 as Exhibit 24(f).)
(f)2-
Power of Attorney for Mark S. Lantrip. (Designated in Form 10-Q for the quarter ended March 31, 2018, File No. 001-37803, as Exhibit 24(f)2.)
     
  Southern Company Gas
     
  (g)1-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016,2017, File No. 1-14174 as Exhibit 24(g).)
     
(g)2-
Power of Attorney for Kimberly S. Greene. (Designated in Form 10-Q for the quarter ended June 30, 2018, File No. 1-14174 as Exhibit 24(g)2.)

Table of Contents

  (31) Section 302 Certifications
     
  Southern Company
     
 *(a)1-
Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
 *(a)2-
Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
  Alabama Power
     
 *(b)1-
Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
 *(b)2-
Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
  Georgia Power
     
 *(c)1-
Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
 *(c)2-
Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
  Gulf Power
     
 *(d)1-
Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
 *(d)2-
Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
  Mississippi Power
     
 *(e)1-
Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
 *(e)2-
Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
  Southern Power
     
 *(f)1-
Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
 *(f)2-
Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     

  Southern Company Gas
     
 *(g)1-
Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     
 *(g)2-
Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
     

Table of Contents

  (32) Section 906 Certifications
     
  Southern Company
     
 *(a)-
Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
     
  Alabama Power
     
 *(b)-
Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
     
  Georgia Power
     
 *(c)-
Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
     
  Gulf Power
     
 *(d)-
Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
     
  Mississippi Power
     
 *(e)-
Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
     
  Southern Power
     
 *(f)-
Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
     
  Southern Company Gas
     
 *(g)-
Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
     
  (99) Additional Exhibits
Georgia Power
(c)-
Co-Owner Term Sheet, dated September 26, 2018, among Georgia Power, Oglethorpe Power Corporation, MEAG, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and the City of Dalton, Georgia. (Designated in Form 8-K dated September 26, 2018, File No. 000-53908 as Exhibit 10.1.)
(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

Table of Contents

THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  THE SOUTHERN COMPANY
    
By Thomas A. Fanning
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Art P. BeattieAndrew W. Evans
  Executive Vice President and Chief Financial Officer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: October 31, 2017November 6, 2018

Table of Contents

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: October 31, 2017November 6, 2018

Table of Contents

GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  GEORGIA POWER COMPANY
    
By W. Paul Bowers
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Xia Liu
  Executive Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: October 31, 2017November 6, 2018

Table of Contents

GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  GULF POWER COMPANY
    
By S. W. Connally, Jr.
  Chairman, President and Chief Executive Officer
  (Principal Executive Officer)
    
By Robin B. Boren
  Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: October 31, 2017November 6, 2018

Table of Contents

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: October 31, 2017November 6, 2018

Table of Contents

SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  SOUTHERN POWER COMPANY
    
By Joseph A. MillerMark 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: October 31, 2017November 6, 2018

Table of Contents

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 Andrew W. EvansKimberly S. Greene
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Elizabeth W. Reese
  Executive Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: October 31, 2017November 6, 2018


292301