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 JuneSeptember 30, 2017
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 JuneSeptember 30, 2017
The Southern Company Par Value $5 Per Share 999,474,0281,003,627,691
Alabama Power Company Par Value $40 Per Share 30,537,500
Georgia Power Company Without Par Value 9,261,500
Gulf Power Company Without Par Value 7,392,717
Mississippi Power Company Without Par Value 1,121,000
Southern Power Company Par Value $0.01 Per Share 1,000
Southern Company Gas Par Value $0.01 Per Share 100
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q
JuneSeptember 30, 2017


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

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
JuneSeptember 30, 2017


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

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
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 ActState of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
CCRCoal combustion residuals
Clean Power Plan
Final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing electric generating units
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
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 Plan
Eligible Project CostsCertain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program
EPAU.S. Environmental Protection Agency
EPC ContractorWestinghouse and its affiliate, WECTEC (formerly known as CB&I Stone & Webster, 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, as applicable
GAAPU.S. generally accepted accounting principles
Georgia PowerGeorgia Power Company
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
IICIntercompany interchange contract
Illinois CommissionIllinois Commerce Commission, the state regulatory agency for Nicor Gas
IRCInternal Revenue Code of 1986, as amended

DEFINITIONS
(continued)
TermMeaning
IRSInternal Revenue Service
ITCInvestment tax credit
Kemper IGCCMississippi Power's IGCC project in Kemper County, Mississippi
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 ruleMercury and Air Toxics Standards rule
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)
NCCRGeorgia Power's Nuclear Construction Cost Recovery
New Jersey BPUNew Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
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
PiedmontPiedmont Natural Gas Company, Inc.
Pivotal Utility HoldingsPivotal Utility Holdings, Inc., a wholly-owned subsidiary of Southern Company Gas, doing business as Elizabethtown Gas, Elkton Gas, 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

DEFINITIONS
(continued)
TermMeaning
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
SMEPASouth Mississippi Electric Power Association (now known as Cooperative Energy)
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 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
SouthStarSouthStar Energy Services, LLC
STRIDEAtlanta Gas Light's Strategic Infrastructure Development and Enhancement program
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
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
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, 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, 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
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 sources of capital, financing activities, completion dates of construction projects, filings with state and federal regulatory authorities, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

the impact of recent and future federal and state regulatory changes, including 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, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

the impact of recent and future federal and state regulatory changes, including 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
(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;
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 by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on 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;
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.


THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail electric revenues$3,777
 $3,748
 $7,171
 $7,124
$4,615
 $4,808
 $11,786
 $11,932
Wholesale electric revenues618
 446
 1,149
 842
718
 613
 1,867
 1,455
Other electric revenues167
 166
 342
 348
168
 181
 510
 529
Natural gas revenues684
 
 2,214
 
532
 518
 2,746
 518
Other revenues184
 99
 326
 137
168
 144
 494
 281
Total operating revenues5,430
 4,459
 11,202
 8,451
6,201
 6,264
 17,403
 14,715
Operating Expenses:              
Fuel1,092
 1,023
 2,088
 1,934
1,285
 1,400
 3,372
 3,334
Purchased power211
 189
 390
 354
256
 227
 646
 581
Cost of natural gas232
 
 951
 
134
 133
 1,085
 133
Cost of other sales114
 58
 203
 77
90
 84
 293
 161
Other operations and maintenance1,301
 1,099
 2,631
 2,206
1,287
 1,411
 3,918
 3,616
Depreciation and amortization754
 569
 1,469
 1,110
767
 695
 2,236
 1,805
Taxes other than income taxes308
 255
 638
 511
303
 309
 941
 821
Estimated loss on Kemper IGCC3,012
 81
 3,120
 134
34
 88
 3,155
 222
Total operating expenses7,024
 3,274
 11,490
 6,326
4,156
 4,347
 15,646
 10,673
Operating Income (Loss)(1,594) 1,185
 (288) 2,125
Operating Income2,045
 1,917
 1,757
 4,042
Other Income and (Expense):              
Allowance for equity funds used during construction58
 45
 115
 98
18
 52
 133
 150
Earnings (loss) from equity method investments28
 (1) 67
 (1)
Earnings from equity method investments32
 29
 100
 28
Interest expense, net of amounts capitalized(424) (293) (840) (539)(407) (374) (1,248) (913)
Other income (expense), net(3) (28) (11) (56)11
 (8) 2
 (66)
Total other income and (expense)(341) (277) (669) (498)(346) (301) (1,013) (801)
Earnings (Loss) Before Income Taxes(1,935) 908
 (957) 1,627
Income taxes (benefit)(587) 261
 (273) 479
Consolidated Net Income (Loss)(1,348) 647
 (684) 1,148
Earnings Before Income Taxes1,699
 1,616
 744
 3,241
Income taxes590
 439
 317
 917
Consolidated Net Income1,109
 1,177
 427
 2,324
Less:              
Dividends on preferred and preference stock of subsidiaries11
 12
 22
 23
10
 11
 32
 34
Net income attributable to noncontrolling interests22
 12
 17
 13
30
 27
 48
 39
Consolidated Net Income (Loss) Attributable to
Southern Company
$(1,381) $623
 $(723) $1,112
Consolidated Net Income Attributable to
Southern Company
$1,069
 $1,139
 $347
 $2,251
Common Stock Data:              
Earnings (loss) per share —       
Earnings per share —       
Basic$(1.38) $0.67
 $(0.73) $1.20
$1.07
 $1.18
 $0.35
 $2.40
Diluted$(1.37) $0.66
 $(0.72) $1.20
$1.06
 $1.17
 $0.35
 $2.38
Average number of shares of common stock outstanding (in millions)              
Basic998
 934
 996
 925
1,003
 968
 998
 940
Diluted1,005
 940
 1,003
 931
1,010
 975
 1,005
 945
Cash dividends paid per share of common stock$0.5800
 $0.5600
 $1.1400
 $1.1025
$0.5800
 $0.5600
 $1.7200
 $1.6625
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 June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Consolidated Net Income (Loss)$(1,348) $647
 $(684) $1,148
Consolidated Net Income$1,109
 $1,177
 $427
 $2,324
Other comprehensive income (loss):              
Qualifying hedges:              
Changes in fair value, net of tax of
$23, $(13), $17, and $(85), respectively
38
 (20) 29
 (137)
Reclassification adjustment for amounts included in net income,
net of tax of $(25), $10, $(26), and $11, respectively
(41) 16
 (42) 18
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, and $1, respectively
1
 1
 2
 2
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)(2) (3) (11) (117)9
 22
 (2) (95)
Comprehensive Income (Loss)(1,350) 644
 (695) 1,031
Comprehensive Income1,118
 1,199
 425
 2,229
Less:              
Dividends on preferred and preference stock of subsidiaries11
 12
 22
 23
10
 11
 32
 34
Comprehensive income attributable to noncontrolling interests22
 12
 17
 13
30
 27
 48
 39
Consolidated Comprehensive Income (Loss) Attributable to
Southern Company
$(1,383) $620
 $(734) $995
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 Six Months Ended June 30,For the Nine Months Ended September 30,
2017 20162017 2016
(in millions)(in millions)
Operating Activities:      
Consolidated net income (loss)$(684) $1,148
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —    
Consolidated net income$427
 $2,324
Adjustments to reconcile consolidated net income to net cash provided from operating activities —    
Depreciation and amortization, total1,683
 1,306
2,564
 2,109
Deferred income taxes(270) 279
15
 (22)
Allowance for equity funds used during construction(115) (98)(133) (150)
Pension, postretirement, and other employee benefits(83) (56)(64) (158)
Settlement of asset retirement obligations(87) (66)(137) (117)
Stock based compensation expense73
 69
Hedge settlements1
 (201)
 (236)
Estimated loss on Kemper IGCC3,120
 134
3,148
 222
Income taxes receivable, non-current(58) 
Other, net(63) 63
(8) (1)
Changes in certain current assets and liabilities —      
-Receivables110
 (197)426
 (458)
-Prepayments(61) (28)
-Fossil fuel for generation6
 70
59
 204
-Natural gas for sale, net of temporary LIFO liquidation223
 

 (222)
-Other current assets(36) (25)(164) (112)
-Accounts payable(353) (71)(467) (9)
-Accrued taxes(132) 74
157
 1,062
-Accrued compensation(331) (222)(230) (122)
-Retail fuel cost over recovery(187) (54)(211) (106)
-Other current liabilities(14) 15
(129) 88
Net cash provided from operating activities2,742
 2,140
5,253
 4,296
Investing Activities:      
Business acquisitions, net of cash acquired(1,062) (897)(1,032) (9,513)
Property additions(3,398) (3,486)(5,242) (5,252)
Investment in restricted cash(16) (8,608)(16) (750)
Distribution of restricted cash27
 649
33
 746
Nuclear decommissioning trust fund purchases(388) (585)(585) (838)
Nuclear decommissioning trust fund sales383
 580
580
 832
Cost of removal, net of salvage(128) (99)(208) (155)
Change in construction payables, net(117) (260)120
 (259)
Investment in unconsolidated subsidiaries(116) 
(134) (1,421)
Payments pursuant to LTSAs(132) (82)(189) (125)
Other investing activities58
 113
(14) 95
Net cash used for investing activities(4,889) (12,675)(6,687) (16,640)
Financing Activities:      
Increase in notes payable, net30
 471
Increase (decrease) in notes payable, net(515) 655
Proceeds —      
Long-term debt2,958
 12,038
4,068
 14,091
Common stock417
 1,383
613
 3,265
Preferred stock250
 
Short-term borrowings1,004
 
1,263
 
Redemptions and repurchases —      
Long-term debt(1,478) (1,272)(1,981) (2,405)
Preference stock(150) 
Preferred and preference stock(150) 
Short-term borrowings
 (475)(409) (475)
Distributions to noncontrolling interests(40) (11)(89) (22)
Capital contributions from noncontrolling interests73
 179
79
 367
Purchase of membership interests from noncontrolling interests
 (129)
 (129)
Payment of common stock dividends(1,134) (1,023)(1,716) (1,553)
Other financing activities(75) (133)(113) (185)
Net cash provided from financing activities1,605
 11,028
1,300
 13,609
Net Change in Cash and Cash Equivalents(542) 493
(134) 1,265
Cash and Cash Equivalents at Beginning of Period1,975
 1,404
1,975
 1,404
Cash and Cash Equivalents at End of Period$1,433
 $1,897
$1,841
 $2,669
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —      
Interest (net of $55 and $61 capitalized for 2017 and 2016, respectively)$833
 $458
Interest (net of $72 and $94 capitalized for 2017 and 2016, respectively)$1,286
 $766
Income taxes, net1
 (138)(187) (151)
Noncash transactions — Accrued property additions at end of period629
 549
805
 578
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)
 
Assets At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $1,433
 $1,975
 $1,841
 $1,975
Receivables —        
Customer accounts receivable 1,600
 1,565
 1,744
 1,583
Energy marketing receivables 482
 623
 427
 623
Unbilled revenues 593
 706
 595
 706
Under recovered regulatory clause revenues 26
 18
Under recovered fuel clause revenues 62
 
Income taxes receivable, current 544
 544
 138
 544
Other accounts and notes receivable 513
 377
 578
 377
Accumulated provision for uncollectible accounts (52) (43) (43) (43)
Materials and supplies 1,461
 1,462
 1,499
 1,462
Fossil fuel for generation 624
 689
 571
 689
Natural gas for sale 477
 631
 631
 631
Prepaid expenses 361
 364
 365
 364
Other regulatory assets, current 569
 581
 585
 581
Other current assets 206
 230
 209
 230
Total current assets 8,837
 9,722
 9,202
 9,722
Property, Plant, and Equipment:        
In service 101,021
 98,416
 102,014
 98,416
Less: Accumulated depreciation 30,667
 29,852
 31,164
 29,852
Plant in service, net of depreciation 70,354
 68,564
 70,850
 68,564
Nuclear fuel, at amortized cost 892
 905
 865
 905
Construction work in progress 7,440
 8,977
 8,026
 8,977
Total property, plant, and equipment 78,686
 78,446
 79,741
 78,446
Other Property and Investments:        
Goodwill 6,271
 6,251
 6,267
 6,251
Equity investments in unconsolidated subsidiaries 1,632
 1,549
 1,637
 1,549
Other intangible assets, net of amortization of $126 and $62
at June 30, 2017 and December 31, 2016, respectively
 929
 970
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 1,722
 1,606
 1,783
 1,606
Leveraged leases 782
 774
 788
 774
Miscellaneous property and investments 230
 270
 236
 270
Total other property and investments 11,566
 11,420
 11,613
 11,420
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 1,325
 1,629
 1,318
 1,629
Unamortized loss on reacquired debt 215
 223
 210
 223
Other regulatory assets, deferred 6,668
 6,851
 6,718
 6,851
Other deferred charges and assets 1,387
 1,406
 1,513
 1,406
Total deferred charges and other assets 9,595
 10,109
 9,759
 10,109
Total Assets $108,684
 $109,697
 $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 June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $3,031
 $2,587
 $3,505
 $2,587
Notes payable 3,274
 2,241
 2,579
 2,241
Energy marketing trade payables 534
 597
 451
 597
Accounts payable 1,920
 2,228
 2,353
 2,228
Customer deposits 546
 558
 550
 558
Accrued taxes —        
Accrued income taxes 125
 193
 176
 193
Unrecognized tax benefits 400
 385
 17
 385
Other accrued taxes 490
 667
 690
 667
Accrued interest 508
 518
 443
 518
Accrued compensation 584
 915
 703
 915
Asset retirement obligations, current 300
 378
 245
 378
Liabilities from risk management activities, net of collateral 71
 107
Acquisitions payable 
 489
 
 489
Other regulatory liabilities, current 169
 236
 139
 236
Other current liabilities 799
 818
 752
 925
Total current liabilities 12,751
 12,917
 12,603
 12,917
Long-term Debt 43,885
 42,629
 44,042
 42,629
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 13,529
 14,092
 14,321
 14,092
Deferred credits related to income taxes 212
 219
Accumulated deferred ITCs 2,301
 2,228
 2,290
 2,228
Employee benefit obligations 2,156
 2,299
 2,139
 2,299
Asset retirement obligations, deferred 4,297
 4,136
 4,356
 4,136
Accrued environmental remediation 399
 397
Other cost of removal obligations 2,706
 2,748
 2,708
 2,748
Other regulatory liabilities, deferred 233
 258
 449
 476
Other deferred credits and liabilities 805
 880
 1,048
 1,278
Total deferred credits and other liabilities 26,638
 27,257
 27,311
 27,257
Total Liabilities 83,274
 82,803
 83,956
 82,803
Redeemable Preferred Stock of Subsidiaries 118
 118
 361
 118
Redeemable Noncontrolling Interests 51
 164
 59
 164
Stockholders' Equity:        
Common Stockholders' Equity:        
Common stock, par value $5 per share —        
Authorized — 1.5 billion shares        
Issued — June 30, 2017: 1.0 billion shares    
Issued — September 30, 2017: 1.0 billion shares    
— December 31, 2016: 991 million shares        
Treasury — June 30, 2017: 0.9 million shares    
Treasury — September 30, 2017: 0.9 million shares    
— December 31, 2016: 0.8 million shares        
Par value 4,997
 4,952
 5,018
 4,952
Paid-in capital 10,106
 9,661
 10,300
 9,661
Treasury, at cost (34) (31) (35) (31)
Retained earnings 8,494
 10,356
 8,981
 10,356
Accumulated other comprehensive loss (191) (180) (182) (180)
Total Common Stockholders' Equity 23,372
 24,758
 24,082
 24,758
Preferred and Preference Stock of Subsidiaries 462
 609
 462
 609
Noncontrolling Interests 1,407
 1,245
 1,395
 1,245
Total Stockholders' Equity 25,241
 26,612
 25,939
 26,612
Total Liabilities and Stockholders' Equity $108,684
 $109,697
 $110,315
 $109,697
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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SECONDTHIRD QUARTER 2017 vs. SECONDTHIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016


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 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 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. Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K. See FUTURE EARNINGS POTENTIAL 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.
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.
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 MattersGeorgia PowerNuclear 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.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.

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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

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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). Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $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.
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions 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 Order,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.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion$34 million ($2.1 billion21 million after tax) for the secondthird quarter 2017 and $3.1$3.2 billion ($2.2 billion after tax) for the sixnine months ended JuneSeptember 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.94.0 billion after tax) through JuneSeptember 30, 2017.
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.
As of JuneSeptember 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 SMEPA.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""Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

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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, 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. On June 9, 2017, Georgia Power

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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, 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, are continuing to conduct comprehensive schedule and cost-to-complete assessments,entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as well as cancellation cost assessments, to determine the impact ofprimary contractor for the EPC Contractor's bankruptcy filing on theremaining construction cost and scheduleactivities for Plant Vogtle Units 3 and 4.
In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related torecommended that construction of Plant Vogtle Units 3 and 4 including, but not limitedbe 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 statusnegotiation of constructiondefinitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and rate recovery,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 currently expectsNote (E) to include its recommendation in its seventeenth Vogtle Construction Monitoring (VCM) reportthe Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to be filed with the Georgia PSC in late August 2017.borrowing.
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. The ultimate outcome of these matters also is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Construction ProgramNuclear Construction"Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

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RESULTS OF OPERATIONS
Net Income (Loss)
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(2,004) N/M $(1,835) N/M
N/M - Not meaningful
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)
Consolidated net lossincome attributable to Southern Company was $(1.4)$1.07 billion ($(1.38)1.07 per share) for the secondthird quarter 2017 compared to $1.14 billion ($1.18 per share) for the corresponding period in 2016. The decrease was primarily due to a decrease in retail electric revenues due to milder weather and lower customer usage, a decrease in tax benefits at Southern Power, and an increase in depreciation and amortization. These changes were partially offset by higher retail electric revenues resulting from increases in base rates and a decrease in operations and maintenance expenses.
Consolidated net income of $623attributable to Southern Company was $347 million ($0.670.35 per share) for year-to-date 2017 compared to $2.3 billion ($2.40 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.0$3.2 billion and $81 million in the second quarter 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases in renewable energy sales at Southern Power, higher retail electric revenues resulting from increases in base rates, and $49 million in net income from Southern Company Gas, which was acquired on July 1, 2016, partially offset by higher interest expense.
Consolidated net loss attributable to Southern Company was $(723) million ($(0.73) per share) for year-to-date 2017 compared to net income of $1.1 billion ($1.20 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.1 billion and $134$222 million for year-to-date 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was $288an 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, and higher retail electric revenues

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resulting from increases in base rates, partially offset by higher interest expense and a decrease in retail electric revenues resulting fromdue to milder weather for year-to-date 2017 compared to the corresponding periodand lower customer usage, higher interest expense, and an increase in 2016.depreciation and amortization.
See Note (B) 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.
Retail Electric Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$29 0.8 $47 0.7
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)
In the secondthird quarter 2017, retail electric revenues were $3.8$4.6 billioncompared to $3.7$4.8 billion for the corresponding period in 2016. For year-to-date 2017, retail electric revenues were $7.2$11.8 billion compared to $7.1$11.9 billion for the corresponding period in 2016.
Details of the changes in retail electric revenues were as follows:
 Second Quarter 2017 Year-to-Date 2017 Third Quarter 2017 Year-to-Date 2017
 (in millions) (% change) (in millions) (% change) (in millions) (% change) (in millions) (% change)
Retail electric – prior year $3,748
   $7,124
   $4,808
   $11,932
  
Estimated change resulting from –                
Rates and pricing 81
 2.2
 200
 2.8
 138
 2.9
 338
 2.8
Sales decline (12) (0.3) (22) (0.3) (52) (1.1) (74) (0.6)
Weather (51) (1.4) (189) (2.6) (162) (3.4) (351) (2.9)
Fuel and other cost recovery 11
 0.3
 58
 0.8
 (117) (2.4) (59) (0.5)
Retail electric – current year $3,777
 0.8 % $7,171
 0.7 % $4,615
 (4.0)% $11,786
 (1.2)%
Revenues associated with changes in rates and pricing increased in the secondthird quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a Rate RSE increase at Alabama Power effective

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January 1, 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an ECO Plan rate increase in retail base revenues effective July 2017 and in environmental cost recovery effective November 2016 at Mississippi Power implemented in the third quarter 2016. Additionally, the second quarter 2017 increase was partially offset by the rate pricing effect of decreased customer usage and lower contributions from commercial and industrial customers under a rate plan for variable demand-driven pricing at GeorgiaGulf Power.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" andPower," " Georgia Power Rate Plans"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 decreased in the secondthird quarter and year-to-date 2017when compared to the corresponding periodperiods in 2016. Industrial KWH sales decreased 0.8% in the second quarter 2017 primarily in the paper, primary metals, and transportation sectors, partially offset by increased sales in the chemicals sector. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Weather-adjusted residential KWH sales decreased 0.4%2.0% and 0.6% in the secondthird quarter 2017primarily due to decreased customer usage primarily resulting from increased efficiency improvements in residential appliances and lighting, partially offset by customer growth. Weather-adjusted commercial KWH sales were flat in thesecond quarteryear-to-date 2017, respectively, primarily due to decreased customer usage resulting from an increase in electronic commerce transactions andpenetration of energy saving initiatives,efficient residential appliances, partially offset by customer growth.
Revenues attributable to changes in Weather-adjusted commercial KWH sales decreased for1.4% and 1.1% in the third quarter and year-to-date 2017, when comparedrespectively, primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the corresponding period in 2016.electronic commerce business model, partially offset by customer growth. Industrial KWH sales decreased 1.5% for0.5% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily in the paper stone, clay,sector, partially offset by increased sales in the primary metals and

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glass, and transportation textile sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Weather-adjusted commercial KWH sales decreased 0.9% foryear-to-date 2017 primarily due to decreasedAdditionally, Hurricane Irma negatively impacted customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset byfor all customer growth. Weather-adjusted residential KWH sales increased 0.2% for year-to-date 2017primarily due to customer growth, partially offset by decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting.classes.
Fuel and other cost recovery revenues increased $11decreased $117 million and $58$59 million in the secondthird quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to an increase in natural gaslower energy sales resulting from milder weather and lower coal prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale Electric Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$172 38.6 $307 36.5
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
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. ElectricityEnergy 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 for electricity.related to the energy. As a result, Southern Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the second quarter 2017, wholesale electric revenues were $618 million compared to $446 million for the corresponding period in 2016. This increase was primarily related to a $158 million increase in energy revenues and a $14 million increase in capacity revenues. For year-to-date 2017, wholesale electric revenues were $1.1 billion compared to $842 million for the corresponding period in 2016. This increase was primarily related to a $276 million increase in energy revenues and a $31 million increase in capacity revenues. The increases in energy revenues primarily related to Southern Power increases in renewable energy sales arising from new solar and wind facilities, sales from new natural gas PPAs, 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 load requirements at Southern Power.
Natural Gas Revenues
Natural gas revenues represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $684 million and $2.2 billion of natural gas revenues are included in the consolidated statements of income for the second quarter and year-to-date 2017, respectively.

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In the third quarter 2017, wholesale electric revenues were $718 million compared to $613 million for the corresponding period in 2016. This increase was primarily related to a $78 million increase in energy revenues and a $27 million increase in capacity revenues. For year-to-date 2017, wholesale electric revenues were $1.9 billion compared to $1.5 billion for the corresponding period in 2016. This increase was primarily related to a $354 million increase 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 requirements 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 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 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 CompanyMerger with Southern Company Gas" herein for additional information.
Other Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$85 85.9 $189 N/M
N/M - Not meaningful
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 secondthird quarter 2017, other revenues were $184$168 million compared to $99$144 million for the corresponding period in 2016. For year-to-date 2017, other revenues were $326$494 million compared to $137$281 million for the corresponding

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period in 2016. These increases were primarily due to increases of $60$5 million and $130$135 million for the secondthird quarter and year-to-date 2017, respectively, from products and services at PowerSecure, which was acquired on May 9, 2016, and $32$8 million and $62$70 million for the secondthird 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-regulated sales of products and services at 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.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Fuel and Purchased Power Expenses
Second Quarter 2017
vs.
Second Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
Third Quarter 2017
vs.
Third Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$69
 6.7 $154
 8.0$(115) (8.2) $38
 1.1
Purchased power22
 11.6 36
 10.229
 12.8 65
 11.2
Total fuel and purchased power expenses$91
 $190
 $(86) $103
 
In the secondthird quarter 2017, total fuel and purchased power expenses were $1.3$1.5 billion compared to $1.2$1.6 billion for the corresponding period in 2016. The increasedecrease was primarily the result of a $154$104 million net decrease in the volume of KWHs generated and purchased, partially offset by an $18 million net increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $63 million decrease primarily due to the volume of KWHs purchased.prices.
For year-to-date 2017, total fuel and purchased power expenses were $2.5$4.0 billion compared to $2.3$3.9 billion for the corresponding period in 2016. The increase was primarily the result of a $277 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by an $87a $174 million decrease primarily due toin the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory MattersFuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

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Details of the Southern Company system's generation and purchased power were as follows:
Second Quarter 2017 Second Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
Total generation (in billions of KWHs)
49 45 93 8954 56 147 145
Total purchased power (in billions of KWHs)
3 4 7 86 6 14 15
Sources of generation (percent)
      
Coal31 32 30 3031 38 30 33
Nuclear16 16 16 1715 15 16 16
Gas43 48 45 4747 44 46 46
Hydro3 2 3 42 1 2 3
Other7 2 6 25 2 6 2
Cost of fuel, generated (in cents per net KWH)
      
Coal2.77 3.20 2.82 3.222.82 2.97 2.82 3.10
Nuclear0.80 0.82 0.80 0.820.80 0.81 0.80 0.82
Gas2.94 2.24 2.93 2.202.92 2.74 2.93 2.40
Average cost of fuel, generated (in cents per net KWH)
2.49 2.33 2.49 2.282.54 2.54 2.51 2.38
Average cost of purchased power (in cents per net KWH)(*)
7.70 5.03 6.85 5.144.96 4.98 5.32 4.75
(*)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 secondthird quarter 2017, fuel expense was $1.1$1.3 billion compared to $1.0$1.4 billion for the corresponding period in 2016. The increasedecrease was primarily due to a 31.3%21.4% decrease in the volume of KWHs generated by coal and a 5.1% decrease in the average cost of coal per KWH generated, partially offset by a 6.6% increase in the average cost of natural gas per KWH generated and a 3.0%1.2% increase in the volume of KWHs generated by coal, partially offset by a 13.4% decrease in the average cost of coal per KWH generated and a 4.8% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2017, fuel expense was $2.1$3.4 billion compared to $1.9$3.3 billion for the corresponding period in 2016. The increase was primarily due to a 33.2%22.1% increase in the average cost of natural gas per KWH generated, and a 4.1% increase in the volume of KWHs generated by coal, partially offset by a 12.4%9.0% decrease in the average cost of coal per KWH generated, a 7.4% decrease in the volume of KWHs generated by coal, and a 6.6%3.7% decrease in the volume of KWHs generated by natural gas.
Purchased Power
In the secondthird quarter 2017, purchased power expense was $211$256 million compared to $189$227 million for the corresponding period in 2016. The increase was primarily due to a 53.1%10.1% increase in the volume of KWHs purchased, partially offset by 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% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 28.0% decrease in the volume of KWHs purchased.
For year-to-date 2017, purchased power expense was $390 million compared to $354 million for the corresponding period in 2016. The increase was primarily due to a 33.3% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 16.8%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.

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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
N/M - Not meaningful
Cost of natural gas represents the cost of natural gas sold by the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. FollowingIn the Merger, $232 millionandthird quarter 2017$951 million, cost of natural gas costs were included in the consolidated statements of incomewas $134 million compared to $133 million for the second quarter andcorresponding period in 2016. For year-to-date 2017, respectively.cost of natural gas was $1.1 billion compared to $133 million for the corresponding period in 2016. The year-to-date 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 CompanyMerger with Southern Company Gas" herein for additional information.
Cost of Other Sales
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$56 96.6% $126 N/M
N/M - Not meaningful
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
In the secondthird quarter 2017, cost of other sales was $114$90 million compared to $58$84 million for the corresponding period in 2016. For year-to-date 2017, cost of other sales was $203$293 million compared to $77$161 million for the corresponding period in 2016. These increases wereThe year-to-date increase primarily due toreflects costs related to sales of products and services by PowerSecure, which was acquired on May 9, 2016, and costs related to gas marketing products and services at Southern Company Gas following the Merger.Merger closing on July 1, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information.
Other Operations and Maintenance Expenses
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$202 18.4 $425 19.3
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
In the secondthird quarter 2017, other operations and maintenance expenses were $1.3 billion compared to $1.1$1.4 billion for the corresponding period in 2016. The increasedecrease was primarily due to $213cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $37 million in operationsmaintenance costs, $9 million in customer accounts, service, and maintenance expenses at Southern Company Gas following the Merger,sales costs, and $8 million in other employee compensation and benefits. Other factors include a $19 million increase associated with new solar, wind, and gas facilities at Southern Power, and a $15 million increase in operations and maintenance expenses at PowerSecure, which was acquired on May 9, 2016. These increases were partially offset by a $24$40 million decrease in acquisition-related expenses and a $7$31 million decrease in scheduled outageemployee compensation and maintenance costs at generation facilities.benefits including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $2.6$3.9 billion compared to $2.2$3.6 billion for the corresponding period in 2016. The increase was primarily due to increases of $467$420 million and $36$32 million in operations and maintenance expenses fromas a result of the inclusion of Southern Company Gas and PowerSecure results for the nine-month period in 2017, respectively, a $35$48 million increase associated with new solar, wind, 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 offset by a $46due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $79 million decrease in scheduled outage and maintenance costs at generation facilities,and $34 million in other employee compensation and benefits. Other factors

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include a $26$32 million decrease in acquisition-related expenses, a $25 million decrease in customer accounts, service, and sales costs primarily at Georgia Power, a $19 million increase in gains from sales of integrated transmission system assets at Georgia Power, and a $16 million decrease in customer accounts, service,scheduled outage and salesmaintenance costs primarily associated with demand-side management costs related to the timing of new programs at Georgia Power, and a $14 million decrease in employee compensation and benefits including pension costs.generation facilities.
See Note (B) to the Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement and Note (I) to the

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Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.
Depreciation and Amortization
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$185 32.5 $359 32.3
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 secondthird quarter 2017, depreciation and amortization was $754$767 million compared to $569$695 million for the corresponding period in 2016. FollowingThe increase is primarily related to additional plant in service at the Merger, $125 million intraditional 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 million as a result of the inclusion of Southern Company Gas is included in the consolidated statements of income for the second quarter 2017.nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects $61$170 million related to additional plant in service at the traditional electric operating companies and Southern Power,Power. The increase was partially offset by $8a $34 million more of a reductionincrease in the reductions in depreciation in the second quarter 2017 compared to the corresponding period in 2016 at Gulf Power, as authorized in itsGulf Power's 2013 rate case settlement approved by the Florida PSC.
For year-to-date 2017, depreciation and amortization was $1.5 billion compared to $1.1 billion for the corresponding period in 2016. Following the Merger, $244 million in depreciation and amortization for Southern Company Gas is included in the consolidated statements of income for year-to-date 2017. Additionally, the increase reflects $122 million related to additional plant in service at the traditional electric operating companies and Southern Power, partially offset by $28 million more of a reduction in depreciation for year-to-date 2017PSC as compared to the corresponding period in 2016 at Gulf Power, as authorized in its 2013 rate case settlement approved by the Florida PSC.2016.
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 NoteNotes (B) and (I) to the Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base Rate Cases" herein for additional information. Also see Note (I) to the Condensed Financial Statements underand "Southern CompanyMerger with Southern Company Gas," respectively, herein for additional information.
Taxes Other Than Income Taxes
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$53 20.8 $127 24.9
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
In the second quarter 2017, taxes other than income taxes were $308 million compared to $255 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $638$941 million compared to $511$821 million for the corresponding period in 2016. These increases wereThe increase primarily related to $44 million and $114 million inreflects the second quarter and year-to-date 2017, respectively, in taxes other than income taxes associated withinclusion of Southern Company Gas followingtaxes for the Merger.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 CompanyMerger with Southern Company Gas" herein for additional information.

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Estimated Loss on Kemper IGCC
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$2,931 N/M $2,986 N/M
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
Prior to the project suspension on June 28, 2017, estimatedEstimated probable losses on the Kemper IGCC of $196$34 million and $305 million$3.2 billion were recorded at Mississippi Power in the secondthird quarter and year-to-date 2017, respectively, compared to $81$88 millionand $134$222 million in the secondthird quarter and year-to-date 2016, respectively. TheseWhile 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. 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 reflectedfor revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC prior to project suspension in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction(construction cost increase isdemonstrated to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).
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 Settlement Order, 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, which includes estimated costs associated with the gasification portions of the plant and lignite mine.
See FUTURE EARNINGS POTENTIAL – "Construction ProgramIntegrated 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
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$13 28.9 $17 17.3
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)
In the secondthird quarter 2017,, AFUDC equity was $58$18 million compared to $45$52 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $115$133 million compared to $98$150 million in the corresponding period in 2016. These increasesdecreases primarily resulted from a higher AFUDC rate and an increase inMississippi Power's suspension of the Kemper IGCC CWIP subject to AFUDC prior to project suspension at Mississippi Power.in June 2017.
See FUTURE EARNINGS POTENTIAL – "Construction ProgramIntegrated Coal Gasification Combined Cycle" and Note (B) 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 million

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Earnings from Equity Method Investments
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$29 N/M $68 N/M
N/M - Not meaningful
In the second quarter and year-to-date 2017, earnings from equity method investments werecompared to $28 million and $67 million, respectively,in the corresponding period in 2016. These increases were primarily related to earnings from Southern Company Gas' equity method investment in SNG effectivein September 2016.
See Note (I)12 to the Condensed Financial Statements under "Southern CompanyMerger withfinancial statements of Southern Company Gas" hereinunder "Southern Company – Investment in Southern Natural Gas" in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$131 44.7 $301 55.8
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
In the secondthird quarter 2017, interest expense, net of amounts capitalized was $424$407 million compared to $293$374 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $16 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to research and experimental (R&E) deductions.
For year-to-date 2017, interest expense, net of amounts capitalized was $840 million$1.2 billion compared to $539$913 million in the corresponding period in 2016. These increases wereThe increase was primarily due to an increase in average outstanding long-term debt primarilyand a $31 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to R&E deductions. In addition, year-to-date 2017 includes an additional $106 million reflecting the nine-month period of interest expense for Southern Company Gas compared to the three-month period subsequent to the Merger closing on July 1, 2016.
See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Section 174 Research and the funding of Southern Power's acquisitionsExperimental Deduction" and construction projects. In addition, following the Merger, $48 millionNotes (E) and $94 million in interest expense of Southern Company Gas was included in the consolidated statements of income for the second quarter and year-to-date 2017, respectively.
See Note (E)(G) to the Condensed Financial Statements herein and Note (I) to the Condensed Financial Statements under "Southern CompanyMerger with Southern Company Gas" herein for additional information.
Other Income (Expense), Net
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$25 89.3 $45 80.4
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$19 N/M $68 N/M
N/M - Not meaningful
In the secondthird quarter 2017, other income (expense), net was $(3)$11 million compared to $(28)$(8) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $(11)$2 million compared to $(56)$(66) million for the corresponding period in 2016. These changes were primarily due to $14 million and $16 million from settlement of contractor litigation claims at Southern Company Gas in the third quarter and year-to-date 2017, respectively, and increases of $6 million and $10 million in customer contributions in aid of construction and contract service revenue at Georgia Power in the third quarter 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 $99$36 million and $116$152 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the secondthird quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power.
See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.

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Income Taxes (Benefit)
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(848) N/M $(752) N/M
N/M - Not meaningful
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)
In the secondthird quarter 2017, income tax benefit was $587taxes were $590 million compared to $439 million for the corresponding period in 2016. The increase was primarily due to a $61 million decrease in income tax expensebenefits from solar ITCs at Southern Power, a $23 million increase in deferred income tax expenses associated with new State of $261Illinois tax legislation and new tax apportionment factors at Southern Company Gas, and a $21 million decrease in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power.
For year-to-date 2017, income taxes were $317 million compared to $917 million for the corresponding period in 2016. The decrease was primarily due to $865$866 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power, partially offset by $31a $226 million inincrease reflecting the nine-month period of income taxes at Southern Company Gas following the Merger.
For year-to-datein 2017 income tax benefit was $273 million compared to income tax expense of $479the three-month period subsequent to the Merger closing on July 1, 2016 and a $44 million for the corresponding period in 2016, primarily due to $886 millionnet decrease in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power. In addition, the change reflects $180 million in taxes at Southern Company Gas following the Merger, partially offset by a net increase in tax benefits of $16 million from renewable tax credits at Southern Power.
See NoteNotes (B), (G) to the Condensed Financial Statements herein, and Note (I) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle," "Effective Tax Rate," and "Southern CompanyMerger with Southern Company Gas," respectively, herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Completion of cost assessments and the determination of future actionsMatters 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 higher multi-family home construction. 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 economic growth. Thethe pace of economic growth and electricity and natural gasdemandthat may be affected by changes in regional and global economic conditions, which may

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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.
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.
On October 15, 2017, a wholly-owned subsidiary of Southern Company Gas 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. for a total cash purchase price of $1.7 billion. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required 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.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis 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, higher 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. 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.

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Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of 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 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.

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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 June 6,September 18, 2017, the EPA proposedpublished 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 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 Southern Company 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.
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

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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 significant impact on Southern Company's financial statements.
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 proceeding itrelated 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 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 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.
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' pipeline 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, the Atlantic Coast Pipeline project received FERC approval.
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 –

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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

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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 sixnine months ended JuneSeptember 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 twothree solar projects in January, 2017June, and June 2017. A third solar project is expected to be placed in service in the third quarterOctober 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 June 9,August 17, 2017, Mississippi Power submitted a CPCN to the Mississippi PSC approved Mississippi Power's CPCN for the approval of construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which if approved, 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 for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – 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 MattersGeorgia PowerFuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.

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Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Integrated Resource Plan" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
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 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 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.
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 regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.
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. UnderAmong 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 consistsconsisted 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%) 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 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 by the Florida PSC in November 2016.

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Southern Company Gas
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 revenues or net income, but will affect cash flows.
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. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit,in December 2017, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

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Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding 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.
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). Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. 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, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017. On June 21, 2017, the Mississippi PSC directed Mississippi Power to pursue a settlement under which the Kemper IGCC would be operated as a natural gas plant rather than an IGCC plant and, 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 plant. SeeFor additional information, see Note 3 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" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters Georgia Power – Nuclear Construction" and " Nuclear ConstructionSouthern Company GasRegulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities,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) to the Condensed Financial Statements under "Southern Power" herein. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersSouthern Company GasRegulatory Infrastructure Programs" herein for information regarding infrastructure improvement programs at the natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.

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Integrated Coal Gasification Combined Cycle
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 Mississippi Public Utilities Staff,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,

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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 remainder of the plant includes the gasifiers and the gas clean-up facilities. 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. Most recently, inIn 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. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
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 recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $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.

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At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions 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 Order,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,

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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 $3.0 billion$34 million ($2.1 billion21 million after tax) for the secondthird quarter 2017 and $3.1$3.2 billion ($2.2 billion after tax) for the sixnine months ended JuneSeptember 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.94.0 billion after tax) through JuneSeptember 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 JuneSeptember 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 SMEPA.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""Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation""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

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Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Mississippi Supreme Court.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

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compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have 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 Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, 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 the 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 (i) 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, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extentprovided. The Interim Assessment Agreement, as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power,amended, expired on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of theJuly 27, 2017.

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completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
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 July 31,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 $400$386 million, of which $354$340 million had been paid or accrued as of JuneSeptember 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183$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 June 23,August 10, 2017, Toshiba released a revised outlookits financial results for fiscal year 2016,the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $5$4.5 billion as of March 31, 2017, and announced that its independent audit process was continuing.June 30, 2017. Toshiba has alsopreviously 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, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the 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.

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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.

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Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into 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 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 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 JuneSeptember 30, 2017, Georgia Power had recovered approximately $1.4$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

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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 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.
Under the terms of the Vogtle Cost Settlement Agreement, the Georgia PSC will determine, for retail ratemaking purposes, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC has approved fifteensixteen VCM reports covering the periods through June 30,December 31, 2016, including construction capital costs incurred, which through that date totaled $3.7$3.9 billion. Georgia Power filed its sixteenthseventeenth VCM report, covering the period from JulyJanuary 1 through December 31, 2016,June 30, 2017, requesting approval of $222$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 27, 2017.6, 2018.
The ultimate outcome of these matters cannot be determined at this time.

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Revised Cost and Schedule
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that itsapproximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 rangesis as follows:
Preliminary in-service dates   
Unit 3February 2021March 2022
Unit 4February 2022March 2023
 (in billions)
Preliminary estimated cost to complete$3.9
$4.6
CWIP as of June 30, 20174.5
 4.5
Guarantee Obligations(1.7) (1.7)
Estimated capital costs$6.7
$7.4
Vogtle Cost Settlement Agreement Revised Forecast(5.7) (5.7)
Estimated net additional capital costs$1.0
$1.7
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
 (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 $3.1 billion to $3.5$3.4 billion, of which approximately $1.4$1.5 billion had been incurred through JuneSeptember 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs to cancel both units is approximately $400$350 million. As a result, as of JuneSeptember 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:
Preliminary Cancellation Cost EstimateCancellation Cost Estimate
(in billions)(in billions)
CWIP as of June 30, 2017$4.5
CWIP as of September 30, 2017$4.6
Financing costs collected, net of tax1.4
1.5
Cancellation costs(*)
0.4
0.4
Total$6.3
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, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.recovery.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.

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Other Matters
As of JuneSeptember 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOELoan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB.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.

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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 ifwhile 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 ifwhile 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.
IfWhile 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.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
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
Approximately $1.2 billionExcluding the Kemper IGCC, approximately $830 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 dueyear. All projected tax benefits previously received for bonus depreciation related to net operating loss projections for the 2017 tax year. Approximately $370 million of the 2017 benefit is dependent upon placing the remainder of the Kemper IGCC were repaid in service by December 31, 2017.connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment any amount previously estimated as bonus depreciationfor income tax purposes, the related deduction would be claimed as a deduction under IRC Section 165. Asin the year of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment.abandonment. See Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"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 has reflected deductions for research and experimental (R&E)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.

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2008 through 2013 to also include such deductions. In December 2016, Southern CompanyPower
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the IRS reached a proposed settlement, subject to approval ofvarious solar entities and facilities will not be affected by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. 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, and would result in a reversal of the related unrecognized tax benefits, excluding 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. This matterreorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be resolvedrecorded in the next 12 months; however, thefourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as 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.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthernCompanyanditssubsidiaries or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,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 January 20, 2017, a purported 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 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.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 defendants Southern Company, certain of its directors, 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' 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 thatand, 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

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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. TheEach 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. TheEach 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. TheEach plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
On June 1,August 15, 2017, Judy Mesirov filed athese two shareholder derivative lawsuitlawsuits were consolidated in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company,and the court deferred the consolidated case until 30 days after certain of its current and former directors, certain of its officers, and certain former Mississippi Power officers. Thefurther action in the purported securities class action 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. The 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. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages, disgorgement of profits, and equitable relief and, on her own 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.discussed above.
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 investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date 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" herein for additional information on the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
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, and Rate Recovery" of Southern Company in Item 7 of the Form 10-K for additional information. Mississippi

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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 project completion date are no longer considered significant accounting estimates. Significant accounting estimates

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for the JuneSeptember 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 Order,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 JuneSeptember 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 SMEPA.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 $5.96$6.00 billion ($3.943.96 billion after tax) through JuneSeptember 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $3.0 billion$34 million ($2.1 billion21 million after tax) and $81$88 million ($5054 million after tax) in the secondthird quarter 2017 and the secondthird quarter 2016, respectively, and total pre-tax charges of $3.1$3.2 billion ($2.2 billion after tax) and $134$222 million ($83137 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 the impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" 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.
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. The new standard also requires enhanced disclosures 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 defined

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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, the FASB issued ASU No. 2017-04,Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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(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 income statement outside 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. 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. Southern Company is currently evaluating the new standard. 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

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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. Southern Company is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company's financial statements.
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 JuneSeptember 30, 2017. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.7$5.3 billion for the first sixnine months of 2017, an increase of $0.6$1.0 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to $1.2an increase of $1.5 billion ofin net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, partially offset by the timing of vendor payments and an increase in under-recovered fuel costs.payments. Net cash used for investing activities totaled $4.9$6.7 billion for the first sixnine months of 2017 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's payments for renewable acquisitions. Net cash provided from financing activities totaled $1.6$1.3 billion for the first sixnine months of 2017 primarily due to net issuances of long-term and short-term debt, partially offset by redemptions of long-term debt and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first sixnine months of 2017 include an increase of $1.8$1.3 billion in total property, plant, and equipment in service, net of depreciation 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; a decreaseacquisitions, largely offset by the $2.9 billion write-down of $1.5 billion in CWIP primarily related to the estimated probable losses ongasification portions of the Kemper IGCC; 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 cash and cash equivalents primarilyacquisitions payable related to acquisition payments at Southern Power; an increase of $2.3 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $1.4$0.7 billion in total common stockholder's equity primarily related to the estimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock; an increase of $1.3 billion in long-term debt (excluding amounts due within a year) to fund the Southern Company system's continuous construction programs and for general corporate purposes; and an increase of $1.0 billion in notes payable primarily due to issuances of short-term bank debt for general corporate purposes.stock.
At the end of the secondthird quarter 2017, the market price of Southern Company's common stock was $47.88$49.14 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.38$23.99 per share, representing a market-to-book ratio of 205%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the secondthird quarter 2017 was $0.58 per share compared to $0.56 per share in the secondthird quarter 2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative

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obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Approximately $3.0Subsequent 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 $3.2 billion will be required through JuneSeptember 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in 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) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. In addition, Southern Power 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 has entered into a loan guarantee agreement (Loanthe Loan Guarantee Agreement)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)Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through JuneAs of September 30, 2017, would allow for borrowings of up to $3.1Georgia Power had borrowed $2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion; however, onFacility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, (LGA Amendment) to clarifywhich provides that further advances are conditioned upon the operationDOE's approval of any agreements entered into in replacement of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under4 Agreement and satisfaction of certain other conditions.

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On September 28, 2017, the terms of the LGA Amendment,DOE issued a conditional commitment to Georgia Power will not request any advancesfor up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement unlessAgreement. Final approval and until such time as Georgia Power has completedissuance of these additional loan guarantees by the Cost AssessmentsDOE cannot be assured and made a determinationare subject to continue constructionthe negotiation of Plant Vogtle Units 3definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and 4 and satisfied certainsatisfaction of other conditions related to continuing construction.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 regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also

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see Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of JuneSeptember 30, 2017, Southern Company's current liabilities exceeded current assets by $3.9$3.4 billion due to notes payable of $3.3 billion (comprised of approximately $0.9 billion at the parent company, $1.2 billion at Georgia Power, $0.1 billion at Gulf Power, $0.4 billion at Southern Power, and $0.6 billion at Southern Company Gas) and long-term debt that is due within one year of $3.0$3.5 billion (comprised of approximately $0.4$1.0 billion at the parent company, $0.4$0.3 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power) and notes payable of $2.6 billion (comprised of approximately $1.1 billion at the parent company, $0.4 billion at Georgia Power, $0.1 billion at Southern Power, and $0.9 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At JuneSeptember 30, 2017, Southern Company and its subsidiaries had approximately $1.4$1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at JuneSeptember 30, 2017 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
20172018201920202022 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)(in millions)
Southern Company(a)
$
$
$
$
$2,000
 $2,000
 $2,000
 $
 $
 $
 $
$
$
$
$
$2,000
 $2,000
 $2,000
 $
 $
 $
 $
Alabama Power3
532


800
 1,335
 1,335
 
 
 
 35

35

500
800
 1,335
 1,335
 
 
 
 35
Georgia Power



1,750
 1,750
 1,732
 
 
 
 




1,750
 1,750
 1,732
 
 
 
 
Gulf Power30
195
25
30

 280
 280
 45
 
 
 40
30
195
25
30

 280
 280
 45
 
 
 40
Mississippi Power113




 113
 100
 
 13
 13
 100
100




 100
 100
 
 
 
 100
Southern Power Company(b)



750
 750
 675
 
 
 
 




750
 750
 728
 
 
 
 
Southern Company Gas(b)(c)




1,900
 1,900
 1,849
 
 
 
 




1,900
 1,900
 1,861
 
 
 
 
Other10
30



 40
 40
 20
 
 20
 20

30



 30
 30
 20
 
 20
 10
Southern Company Consolidated$156
$757
$25
$30
$7,200
 $8,168
 $8,011
 $65
 $13
 $33
 $195
$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.

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

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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 JuneSeptember 30, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the 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 JuneSeptember 30, 2017 was approximately $1.6 billion.$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. In addition, at JuneSeptember 30, 2017, the traditional electric operating companies had approximately $626$699 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 of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
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.

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Details of short-term borrowings were as follows:
 
Short-term Debt at
June 30, 2017
 
Short-term Debt During the Period(*)
 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
 
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 $2,257
 1.5% $2,519
 1.3% $2,946
 $1,725
 1.5% $1,895
 1.5% $2,284
Short-term bank debt 1,017
 2.0% 321
 2.0% 1,017
 854
 2.0% 938
 2.1% 1,017
Total $3,274
 1.7% $2,840
 1.4%   $2,579
 1.7% $2,833
 1.7%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended JuneSeptember 30, 2017.
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 JuneSeptember 30, 2017, 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,

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transmission, and interest rate management, and foreign currency risk management, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.management.
The maximum potential collateral requirements under these contracts at JuneSeptember 30, 2017 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and/or Baa2$39
$38
At BBB- and/or Baa3$642
$647
At BB+ and/or Ba1(*)
$2,555
$2,352
(*)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, Moody's revised its rating outlook for Mississippi Power from under review to stable.

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Financing Activities
During the first sixnine months of 2017, Southern Company issued approximately 7.810.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $352$479 million.
In addition, during the second quarterand third quarters of 2017, Southern Company issued a total of approximately 1.32.7 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 $65$134 million, net of $553,000$1.1 million in fees and commissions.

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The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first sixnine months of 2017:
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 and Redemptions
 
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
 $
 $
 $500
 $400
$300
 $400
 $
 $500
 $400
Alabama Power550
 200
 
 
 
550
 200
 36
 
 
Georgia Power850
 450
 27
 
 3
1,350
 450
 65
 370
 13
Gulf Power300
 85
 
 6
 
300
 85
 
 6
 
Mississippi Power
 
 
 40
 893

 
 
 40
 893
Southern Power
 
 
 3
 3

 
 
 43
 4
Southern Company Gas(c)
450
 
 
 
 
450
 
 
 200
 22
Other
 
 
 
 8

 
 
 
 12
Elimination(d)

 
 
 (40) (591)
 
 
 (40) (599)
Southern Company Consolidated$2,450
 $735
 $27
 $509
 $716
$2,950
 $1,135
 $101
 $1,119
 $745
(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)IntercompanyIncludes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness2057 and for other general corporate purposes.
Also in June 2017, Southern Company issued $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 used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.

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Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
Except as described herein, Southern Company's subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs.
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A portion of thePreferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds of Gulf Power's senior note issuances waswere used in JuneOctober 2017 to redeem 550,000 shares ($55all 2 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)stated capital) of GulfAlabama Power's 6.50% Series 2013A 5.60% Preference Stock.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.
In MarchSubsequent to September 30, 2017, GulfAlabama Power extended therepaid at maturity $325 million aggregate principal amount of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 toSeries Q 5.50% Senior Notes due October 2017 and subsequently repaid the loan in May15, 2017.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, which mature onwith maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018,

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respectively, andwhich 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 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.
SubsequentIn September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, June 30,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.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds in a private placement,3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage

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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 of which is expected to be issued in each of August 2017 and November 2017.
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.

PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the sixnine months ended JuneSeptember 30, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to 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) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, 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 secondthird quarter 2017 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.

ALABAMA POWER COMPANY

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$1,333
 $1,316
 $2,560
 $2,510
$1,595
 $1,629
 $4,155
 $4,139
Wholesale revenues, non-affiliates68
 67
 133
 130
77
 82
 210
 211
Wholesale revenues, affiliates32
 9
 65
 31
18
 18
 83
 49
Other revenues51
 52
 108
 105
50
 56
 158
 162
Total operating revenues1,484
 1,444
 2,866
 2,776
1,740
 1,785
 4,606
 4,561
Operating Expenses:              
Fuel303
 295
 601
 564
343
 410
 944
 973
Purchased power, non-affiliates40
 40
 75
 76
57
 63
 132
 139
Purchased power, affiliates34
 55
 62
 88
55
 41
 117
 129
Other operations and maintenance375
 355
 743
 747
391
 348
 1,134
 1,097
Depreciation and amortization183
 175
 364
 347
185
 177
 549
 524
Taxes other than income taxes95
 94
 191
 191
93
 96
 284
 286
Total operating expenses1,030
 1,014
 2,036
 2,013
1,124
 1,135
 3,160
 3,148
Operating Income454
 430
 830
 763
616
 650
 1,446
 1,413
Other Income and (Expense):              
Allowance for equity funds used during construction8
 6
 16
 16
11
 7
 27
 23
Interest expense, net of amounts capitalized(77) (74) (153) (147)(76) (77) (229) (224)
Other income (expense), net1
 (4) (4) (11)(5) (5) (8) (16)
Total other income and (expense)(68) (72) (141) (142)(70) (75) (210) (217)
Earnings Before Income Taxes386
 358
 689
 621
546
 575
 1,236
 1,196
Income taxes151
 140
 277
 242
216
 219
 493
 462
Net Income235
 218
 412
 379
330
 356
 743
 734
Dividends on Preferred and Preference Stock5
 5
 9
 9
5
 4
 14
 13
Net Income After Dividends on Preferred and Preference Stock$230
 $213
 $403
 $370
$325
 $352
 $729
 $721

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Net Income$235
 $218
 $412
 $379
$330
 $356
 $743
 $734
Other comprehensive income (loss):              
Qualifying hedges:              
Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively
 
 
 (2)
 
 
 (2)
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $1, and $1, respectively
1
 1
 2
 2
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $2, respectively
1
 1
 3
 3
Total other comprehensive income (loss)1
 1
 2
 
1
 1
 3
 1
Comprehensive Income$236
 $219
 $414
 $379
$331
 $357
 $746
 $735
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 Six Months Ended June 30,For the Nine Months Ended September 30,
2017 20162017 2016
(in millions)(in millions)
Operating Activities:      
Net income$412
 $379
$743
 $734
Adjustments to reconcile net income to net cash provided from operating activities —      
Depreciation and amortization, total442
 419
666
 634
Deferred income taxes192
 175
260
 267
Allowance for equity funds used during construction(27) (23)
Pension, postretirement, and other employee benefits(24) (23)(4) (14)
Other, net4
 (33)43
 (12)
Changes in certain current assets and liabilities —      
-Receivables(58) 64
(163) (4)
-Fossil fuel stock13
 (32)34
 18
-Other current assets(75) (67)(58) (46)
-Accounts payable(154) (75)(125) (113)
-Accrued taxes52
 102
159
 207
-Accrued compensation(74) (50)(48) (22)
-Retail fuel cost over recovery(65) (60)(76) (104)
-Other current liabilities7
 8
7
 19
Net cash provided from operating activities672
 807
1,411
 1,541
Investing Activities:      
Property additions(738) (645)(1,211) (947)
Nuclear decommissioning trust fund purchases(117) (200)(174) (275)
Nuclear decommissioning trust fund sales117
 200
174
 275
Cost of removal, net of salvage(54) (51)(82) (70)
Change in construction payables48
 (27)105
 (37)
Other investing activities(15) (18)(29) (28)
Net cash used for investing activities(759) (741)(1,217) (1,082)
Financing Activities:      
Proceeds —      
Senior notes550
 400
550
 400
Capital contributions from parent company327
 237
337
 253
Preferred stock250
 
Other long-term debt
 45

 45
Redemptions — Senior notes(200) (200)
Redemptions —

 
Pollution control revenue bonds(36) 
Senior notes(200) (200)
Payment of common stock dividends(357) (382)(536) (574)
Other financing activities(14) (17)(26) (21)
Net cash provided from financing activities306
 83
Net cash provided from (used for) financing activities339
 (97)
Net Change in Cash and Cash Equivalents219
 149
533
 362
Cash and Cash Equivalents at Beginning of Period420
 194
420
 194
Cash and Cash Equivalents at End of Period$639
 $343
$953
 $556
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —      
Interest (net of $6 and $7 capitalized for 2017 and 2016, respectively)$140
 $131
Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively)$217
 $215
Income taxes, net88
 (122)146
 (70)
Noncash transactions — Accrued property additions at end of period132
 94
189
 84
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)
 
Assets At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $639
 $420
 $953
 $420
Receivables —        
Customer accounts receivable 357
 348
 428
 348
Unbilled revenues 161
 146
 149
 146
Other accounts and notes receivable 36
 27
 47
 27
Affiliated 33
 40
 45
 40
Accumulated provision for uncollectible accounts (9) (10) (8) (10)
Fossil fuel stock 191
 205
 171
 205
Materials and supplies 443
 435
 455
 435
Prepaid expenses 86
 34
 58
 34
Other regulatory assets, current 135
 149
 122
 149
Other current assets 7
 11
 5
 11
Total current assets 2,079
 1,805
 2,425
 1,805
Property, Plant, and Equipment:        
In service 26,466
 26,031
 26,619
 26,031
Less: Accumulated provision for depreciation 9,354
 9,112
 9,463
 9,112
Plant in service, net of depreciation 17,112
 16,919
 17,156
 16,919
Nuclear fuel, at amortized cost 333
 336
 314
 336
Construction work in progress 668
 491
 928
 491
Total property, plant, and equipment 18,113
 17,746
 18,398
 17,746
Other Property and Investments:        
Equity investments in unconsolidated subsidiaries 67
 66
 65
 66
Nuclear decommissioning trusts, at fair value 848
 792
 869
 792
Miscellaneous property and investments 119
 112
 121
 112
Total other property and investments 1,034
 970
 1,055
 970
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 526
 525
 525
 525
Deferred under recovered regulatory clause revenues 6
 150
 17
 150
Other regulatory assets, deferred 1,209
 1,157
 1,191
 1,157
Other deferred charges and assets 166
 163
 178
 163
Total deferred charges and other assets 1,907
 1,995
 1,911
 1,995
Total Assets $23,133
 $22,516
 $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 June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $361
 $561
 $325
 $561
Accounts payable —        
Affiliated 242
 297
 275
 297
Other 317
 433
 376
 433
Customer deposits 91
 88
 92
 88
Accrued taxes —        
Accrued income taxes 39
 45
 115
 45
Other accrued taxes 97
 42
 128
 42
Accrued interest 81
 78
 75
 78
Accrued compensation 125
 193
 151
 193
Other regulatory liabilities, current 15
 85
 4
 85
Other current liabilities 63
 76
 50
 76
Total current liabilities 1,431
 1,898
 1,591
 1,898
Long-term Debt 7,082
 6,535
 7,083
 6,535
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 4,842
 4,654
 4,919
 4,654
Deferred credits related to income taxes 64
 65
 60
 65
Accumulated deferred ITCs 113
 110
 118
 110
Employee benefit obligations 269
 300
 289
 300
Asset retirement obligations 1,543
 1,503
 1,564
 1,503
Other cost of removal obligations 648
 684
 630
 684
Other regulatory liabilities, deferred 84
 100
 93
 100
Other deferred credits and liabilities 69
 63
 51
 63
Total deferred credits and other liabilities 7,632
 7,479
 7,724
 7,479
Total Liabilities 16,145
 15,912
 16,398
 15,912
Redeemable Preferred Stock 85
 85
 329
 85
Preference Stock 196
 196
 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 2,950
 2,613
 2,961
 2,613
Retained earnings 2,564
 2,518
 2,711
 2,518
Accumulated other comprehensive loss (29) (30) (28) (30)
Total common stockholder's equity 6,707
 6,323
 6,866
 6,323
Total Liabilities and Stockholder's Equity $23,133
 $22,516
 $23,789
 $22,516
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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



SECONDTHIRD QUARTER 2017 vs. SECONDTHIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016


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 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.
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
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
(% change)
(change in millions)
(% change)
$17 8.0 $33 8.9
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
Alabama Power's net income after dividends on preferred and preference stock for the secondthird quarter 2017 was $230$325 million compared to $213$352 million for the corresponding period in 2016. The increasedecrease was primarily related to an increase in rates under Rate RSE effective January 1, 2017 and an increase in other income (expense), net. These increases were partially offset by an increase in operations and maintenance expenses and a decrease in retail revenues associated with milder weather and lower customer usage in the secondthird quarter 2017 compared to the corresponding period in 2016.2016 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 2017 was $403$729 million compared to $370$721 million for the corresponding period in 2016. The increase was primarily related to an increase in rates under Rate RSE effective January 1, 2017, partially offset by a decrease in retail revenues associated with milder weather and lower customer usage for year-to-date 2017 compared to the corresponding period in 2016.2016, and an increase in non-fuel operations and maintenance expenses.
Retail Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$17 1.3 $50 2.0
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
In the secondthird quarter 2017, retail revenues were $1.33$1.60 billion compared to $1.32$1.63 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $2.56$4.16 billion compared to $2.51$4.14 billion for the corresponding period in 2016.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Details of the changes in retail revenues were as follows:
Second Quarter 2017
Year-to-Date 2017Third Quarter 2017
Year-to-Date 2017
(in millions)
(% change)
(in millions)
(% change)(in millions)
(% change)
(in millions)
(% change)
Retail – prior year$1,316
   $2,510
  $1,629
   $4,139
  
Estimated change resulting from –              
Rates and pricing75
 5.7
 154
 6.2
85
 5.2
 240
 5.8
Sales decline(11) (0.8) (12) (0.5)(18) (1.1) (31) (0.7)
Weather(11) (0.8) (66) (2.6)(50) (3.1) (116) (2.8)
Fuel and other cost recovery(36) (2.8) (26) (1.1)(51) (3.1) (77) (1.9)
Retail – current year$1,333
 1.3% $2,560
 2.0%$1,595
 (2.1)% $4,155
��0.4%
Revenues associated with changes in rates and pricing increased in the secondthird quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in rates under Rate RSE effective January 1, 2017. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the secondthird quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 1.1%2.4% and 0.2%1.1% for the secondthird quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from an increase in efficiency improvements inpenetration of energy efficient residential appliances, and lighting, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 0.4%2.3% and 0.8%1.4% for the secondthird quarter and year-to-date 2017, respectively, primarily due to lower customer usage.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 increased 1.0%1.8% and 0.6% for the secondthird quarter and year-to-date 2017, when compared to the corresponding period in 2016respectively, as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors, partially offset by a decrease in demand from the paper, primary metals, pipelines, and lumber sectors. Industrial KWH sales remained flat year-to-date 2017 when compared to the corresponding period in 2016 as a result of an increase in demand resulting from changes in production levels primarily in the chemicals and mining sectors, offset by a decrease in demand from the pipelines, lumber, and stone, clay, and glass sectors.pipeline sector.
Revenues resulting from changes in weather decreased in the secondthird quarter and year-to-date 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2016. For the secondthird quarter 2017, the resulting decreases were 1.5%5.1% and 0.7%2.4% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.4%1.8% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the secondthird quarter 2017 and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increasea decrease in wholesale revenues to affiliates, which offsets retail fuelKWH generation and a decrease in the average cost recovery.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.
Wholesale Revenues Affiliates
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$23 255.6 $34 109.7
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
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

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the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
In the second quarterFor year-to-date 2017, wholesale revenues from sales to affiliates were $32$83 million compared to $9$49 million for the corresponding period in 2016. The increase was primarily due to a 175.0% increase in KWH sales as a result of lower cost Alabama Power-owned generation available to the Southern Company system and a 29.3% increase in the price of energy due to an increase in natural gas prices. For year-to-date 2017, wholesale revenues from sales to affiliates were $65 million compared to $31 million for the corresponding period in 2016. The increase was primarily due to an 83.5%52% increase in KWH sales as a result of supporting Southern Company system transmission reliability and a 15.5%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
Second Quarter 2017
vs.
Second Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
Third Quarter 2017
vs.
Third Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
(change in millions)
(% change) (change in millions) (% change)(change in millions)
(% change) (change in millions) (% change)
Fuel$8
 2.7 $37
 6.6
$(67) (16.3) $(29) (3.0)
Purchased power – non-affiliates
  (1) (1.3)(6) (9.5) (7) (5.0)
Purchased power – affiliates(21) (38.2) (26) (29.5)14
 34.1 (12) (9.3)
Total fuel and purchased power expenses$(13) $10
  $(59) $(48)  
In the secondthird quarter 2017, fuel and purchased power expenses were $377$455 million compared to $390$514 million for the corresponding period in 2016. The decrease was primarily due to a $55$43 million net decrease inrelated to the volume of KWHs purchased. Thisgenerated and purchased and a $16 million decrease was partially offset by a $24 million net increase related to the average cost of purchased power and fuel and an $18 million increase related to the volume of KWHs generated.fuel.
For year-to-date 2017, fuel and purchased power expenses were $738 million$1.19 billion compared to $728 million$1.24 billion for the corresponding period in 2016. The increasedecrease was primarily due to a $58 million increase in the volume of KWHs generated and a $31 million net increase related to the average cost of purchased power and fuel. These increases were partially offset by a $79$53 million decrease in the volume of KWHs purchased.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.
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.

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Details of Alabama Power's generation and purchased power were as follows:
Second Quarter 2017 Second Quarter 2016 Year-to-Date 2017
Year-to-Date 2016Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017
Year-to-Date 2016
Total generation (in billions of KWHs)
15 13 30 2816 18 46 46
Total purchased power (in billions of KWHs)
1 3 2 42 2 5 6
Sources of generation (percent)
  
Coal47 53 48 4652 59 49 51
Nuclear25 23 26 2524 22 25 24
Gas20 20 20 1919 18 20 19
Hydro8 4 6 105 1 6 6
Cost of fuel, generated (in cents per net KWH)
  
Coal2.63 2.84 2.61 2.852.61 2.73 2.61 2.80
Nuclear0.76 0.79 0.75 0.780.75 0.77 0.75 0.78
Gas2.75 2.52 2.76 2.492.72 2.85 2.74 2.62
Average cost of fuel, generated (in cents per net KWH)(a)
2.14 2.28 2.13 2.202.17 2.32 2.15 2.25
Average cost of purchased power (in cents per net KWH)(b)
7.11 3.94 6.92 4.375.65 5.70 5.57 4.81
(a)
KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)
Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
For year-to-dateIn the third quarter 2017, fuel expense was $601$343 million compared to $564$410 million for the corresponding period in 2016. The increasedecrease was primarily due to increases of 11.0% and 8.4%an 18.4% decrease in the volume of KWHs generated by coal, and natural gas, respectively, a 10.8% increase4.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 28.1%4.4% decrease in average cost of coal per KWH generated. In addition, there was a 194.0% increase in the volume of KWHs generated by hydro facilities.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 increasedecrease was partially offset by an 8.4%primarily due to a 6.8% decrease in the average cost of coal per KWH generated.generated and a 2.0% 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 secondthird quarter 2017, purchased power expense from affiliates was $34$55 million compared to $55$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 61.1%26.6% decrease in the amount of energy purchased due to a decrease in demand as a result of lower cost Alabama Power-owned generation,milder weather in 2017, partially offset by a 60.3%22.9% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.
For year-to-date 2017, purchased power expense from affiliates was $62 million compared to $88 million for the corresponding period in 2016. The decrease was primarily related to a 56.1% decrease in the amount
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Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

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Other Operations and Maintenance Expenses
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$20 5.6 $(4) (0.5)
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
In the secondthird quarter 2017, other operations and maintenance expenses were $375$391 million compared to $355$348 million for the corresponding period in 2016. The increase was primarily due to increases of $13$26 million in scheduled generation outage costs, $11 million in vegetation management costs, $7and $3 million in employee compensation and benefit costs, including pension costs.
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 $3$7 million in employee compensation and benefit costs. The increase wascosts, including pension costs, partially offset by a $4an $11 million decrease in scheduled other power generation outage costs.contract services.
Depreciation and Amortization
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
Third Quarter 2017 vs. Third Quarter 2016Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change) (% change) (change in millions) (% change)
$8 4.6 $17 4.9 4.5 $25 4.8
In the secondthird quarter 2017, depreciation and amortization was $183$185 million compared to $175$177 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $364$549 million compared to $347$524 million for the corresponding period in 2016. These increases were primarily due to additional plant in service related to distribution, steam generation, and transmission assets. In addition, there was an increase in depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and asset retirement obligation recovery, and other generation assets, partially offset by a decrease in distribution-related depreciation rates. 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.
Other Income (Expense), Net
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$5 125.0 $7 63.6
In the second quarter 2017, other income (expense), net was $1 million compared to $(4) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $(4) million compared to $(11) million for the corresponding period in 2016. The changes were primarily due to decreases in donations and increases in sales of non-utility property and unregulated lighting services in 2017.
Income Taxes
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$11 7.9 $35 14.5
In the second quarter 2017, income taxes were $151 million compared to $140 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings.
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
For year-to-date 2017, income taxes were $277$493 million compared to $242$462 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings, and unrecognized tax benefits related to certain state deductions for federal income taxes.taxes, and prior year tax return actualization.

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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 primarily by customer growth. Earnings will also depend upon

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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. 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 economic growth. Thethe pace of economic growth and electricity demandthat 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
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Alabama 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 June 6,September 18, 2017, the EPA proposedpublished 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.

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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 Alabama 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

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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 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 proceeding itrelated 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, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Alabama 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 Alabama 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 matters 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 for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the 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.

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TheultimateoutcomeofsuchpendingorpotentiallitigationagainstAlabama Power or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,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

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Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
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.
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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from 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. The majority of Alabama 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. 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 standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama 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-effectcumulative-

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effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may 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 Cost and Net Periodic Postretirement Benefit Cost (ASU(ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items

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as other compensation costs and requires the other 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 component 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. Alabama Power is currently evaluating the new standard. 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 income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a 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 adoption of ASU 2017-12 is not expected to have a material impact on Alabama Power's financial statements.
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 JuneSeptember 30, 2017. 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 $672 million$1.4 billion for the first sixnine months of 2017, a decrease of $135$130 million as compared to the first sixnine months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation. Net cash used for investing activities totaled $759 million$1.2 billion for the first sixnine months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $306$339 million for the first sixnine months of 2017 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. 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 sixnine months of 2017 include increases of $547$652 million in property, plant, and equipment primarily due to additions to distribution, transmission, and steam generation, $548 million in long-term debt primarily due to the issuance of additional senior notes, $367$533 million in property, plant,cash and equipment, primarily due to additions to distribution, steam generation, and transmission, $337cash equivalents, $348 million in additional paid-in capital due to capital contributions from Southern Company, and $219$265 million in cash

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accumulated deferred income taxes primarily due to bonus depreciation, and cash equivalents,$244 million in redeemable preferred stock primarily due to the September 2017 issuance, as well as a decrease of $200$236 million in securities due within one year.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $361Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017. No additional funds will be required through JuneSeptember 30, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.

Alabama Power's Board of Directors approved its construction program that is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. 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 billion for 2018, $0.1 billion for 2019, $0.2 billion for 2020, $0.3 billion for 2021, and $0.3 billion for 2022. 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 limit CO2 emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units.
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ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in Alabama Power's asset retirement obligation liabilities. These costs, which could change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $27 million for 2018, $101 million for 2019, $105 million for 2020, $107 million for 2021, and $109 million for 2022. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K 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 statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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, 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At JuneSeptember 30, 2017, Alabama Power had approximately $639$953 million of cash and cash equivalents. Committed credit arrangements with banks at JuneSeptember 30, 2017 were as follows:
ExpiresExpires     Expires Within One YearExpires     Expires Within One Year
2017 2018 2022 Total Unused Term Out No Term Out
20182018 2020 2022 Total Unused Term Out No Term Out
(in millions)
$3
 $532
 $800
 $1,335
 $1,335
 $
 $35
35
 $500
 $800
 $1,335
 $1,335
 $
 $35
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, inIn May 2017 and September 2017, Alabama Power amended its $800 million and $500 million multi-year credit arrangement,arrangements, which, among other things, extended the maturity datedates from 2020 to 2022.2022 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 JuneSeptember 30, 2017, 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 $890$854 million as of JuneSeptember 30, 2017. At JuneSeptember 30, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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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.

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Details of commercial paper 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 $28
 1.1% $200
  
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
(*)Average and maximum amounts are based upon daily balances during the three-month period ended JuneSeptember 30, 2017. No short-term debt was outstanding at JuneSeptember 30, 2017.
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 JuneSeptember 30, 2017, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at JuneSeptember 30, 2017 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
$2
Below BBB- and/or Baa3$326
$338
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or 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 Alabama Power 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 credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In February 2017, Alabama Power repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to June 30,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).

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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, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
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.

GEORGIAVogtle 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 the 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.

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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, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the 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.

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Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into 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 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 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

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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 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.

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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.

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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.
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.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
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
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. 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 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.

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Southern Power
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate 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 result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as 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 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 January 20, 2017, a purported 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 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 defendants Southern Company, certain of its directors, 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' 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

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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 behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees 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 consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
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 investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date 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" herein for additional information on the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
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, and Rate Recovery" of Southern Company 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 project completion date are no longer considered significant accounting estimates. Significant accounting estimates

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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, 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.
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 the impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
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.
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. The new standard also requires enhanced disclosures 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 defined

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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, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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 other 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 component 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 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

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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. Southern Company is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company's financial statements.
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. 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 billion for the first nine months of 2017, an increase of $1.0 billion from the corresponding period in 2016. 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 by the timing of vendor payments. Net cash used for investing activities totaled $6.7 billion for the first nine months of 2017 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. Net cash provided from financing activities totaled $1.3 billion for the first nine months of 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include an increase of $1.3 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, largely offset by the $2.9 billion write-down of the gasification portions of the Kemper IGCC; 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 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $0.7 billion in total common stockholder's equity primarily related to the estimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock.
At the end of the third quarter 2017, the market price of Southern Company's common stock was $49.14 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book ratio of 205%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the third quarter 2017 was $0.58 per share compared to $0.56 per share in the third quarter 2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative

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obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Subsequent 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 $3.2 billion will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes 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) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear 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.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. In addition, Southern Power 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) 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, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On 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.

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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 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 regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of September 30, 2017, Southern Company's current liabilities exceeded current assets by $3.4 billion due to long-term debt that is due within one year of $3.5 billion (comprised of approximately $1.0 billion at the parent company, $0.3 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power) and notes payable of $2.6 billion (comprised of approximately $1.1 billion at the parent company, $0.4 billion at Georgia Power, $0.1 billion at Southern Power, and $0.9 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At September 30, 2017, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
 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.

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See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the 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, 2017 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. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 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 of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
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.

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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 $1,725
 1.5% $1,895
 1.5% $2,284
Short-term bank debt 854
 2.0% 938
 2.1% 1,017
Total $2,579
 1.7% $2,833
 1.7%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.
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, 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.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$38
At BBB- and/or Baa3$647
At BB+ and/or Ba1(*)
$2,352
(*)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, Moody's revised its rating outlook for Mississippi Power from under review to stable.

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

Financing Activities
During the first nine months of 2017, Southern Company issued approximately 10.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $479 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 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 million, net of $1.1 million in fees and commissions.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2017:
Company
Senior
Note Issuances
 
Senior
Note Maturities and Redemptions
 
Revenue
Bond
Maturities, Redemptions, and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt Redemptions
and
Maturities(a)
 (in millions)
Southern Company(b)
$300
 $400
 $
 $500
 $400
Alabama Power550
 200
 36
 
 
Georgia Power1,350
 450
 65
 370
 13
Gulf Power300
 85
 
 6
 
Mississippi Power
 
 
 40
 893
Southern Power
 
 
 43
 4
Southern Company Gas(c)
450
 
 
 200
 22
Other
 
 
 
 12
Elimination(d)

 
 
 (40) (599)
Southern Company Consolidated$2,950
 $1,135
 $101
 $1,119
 $745
(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 and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 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 used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.

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

Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
Except as described herein, Southern Company's subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs.
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 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.
Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
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 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.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage

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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.
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.

PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to 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) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, 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 2017 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.

ALABAMA POWER COMPANY

GEORGIAALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$1,904
 $1,907
 $3,593
 $3,624
$1,595
 $1,629
 $4,155
 $4,139
Wholesale revenues, non-affiliates40
 40
 79
 82
77
 82
 210
 211
Wholesale revenues, affiliates9
 10
 17
 15
18
 18
 83
 49
Other revenues95
 94
 191
 202
50
 56
 158
 162
Total operating revenues2,048
 2,051
 3,880
 3,923
1,740
 1,785
 4,606
 4,561
Operating Expenses:              
Fuel445
 439
 815
 815
343
 410
 944
 973
Purchased power, non-affiliates103
 92
 191
 175
57
 63
 132
 139
Purchased power, affiliates138
 111
 310
 250
55
 41
 117
 129
Other operations and maintenance399
 439
 781
 896
391
 348
 1,134
 1,097
Depreciation and amortization223
 214
 444
 425
185
 177
 549
 524
Taxes other than income taxes101
 100
 199
 197
93
 96
 284
 286
Total operating expenses1,409
 1,395
 2,740
 2,758
1,124
 1,135
 3,160
 3,148
Operating Income639
 656
 1,140
 1,165
616
 650
 1,446
 1,413
Other Income and (Expense):              
Allowance for equity funds used during construction11
 7
 27
 23
Interest expense, net of amounts capitalized(104) (99) (205) (193)(76) (77) (229) (224)
Other income (expense), net16
 8
 36
 26
(5) (5) (8) (16)
Total other income and (expense)(88) (91) (169) (167)(70) (75) (210) (217)
Earnings Before Income Taxes551
 565
 971
 998
546
 575
 1,236
 1,196
Income taxes199
 211
 355
 371
216
 219
 493
 462
Net Income352
 354
 616
 627
330
 356
 743
 734
Dividends on Preferred and Preference Stock5
 5
 9
 9
5
 4
 14
 13
Net Income After Dividends on Preferred and Preference Stock$347
 $349
 $607
 $618
$325
 $352
 $729
 $721

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Net Income$352
 $354
 $616
 $627
$330
 $356
 $743
 $734
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
 1
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
Total other comprehensive income (loss)1
 1
 2
 1
1
 1
 3
 1
Comprehensive Income$353
 $355
 $618
 $628
$331
 $357
 $746
 $735
The accompanying notes as they relate to GeorgiaAlabama Power are an integral part of these condensed financial statements.

GEORGIAALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months Ended June 30,For the Nine Months Ended September 30,
2017 20162017 2016
(in millions)(in millions)
Operating Activities:      
Net income$616
 $627
$743
 $734
Adjustments to reconcile net income to net cash provided from operating activities --   
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total543
 530
666
 634
Deferred income taxes159
 157
260
 267
Allowance for equity funds used during construction(25) (24)(27) (23)
Deferred expenses41
 39
Pension, postretirement, and other employee benefits(45) (28)(4) (14)
Settlement of asset retirement obligations(62) (52)
Other, net(39) 36
43
 (12)
Changes in certain current assets and liabilities —      
-Receivables(150) (25)(163) (4)
-Fossil fuel stock(32) 61
34
 18
-Other current assets(22) 10
(58) (46)
-Accounts payable(153) 6
(125) (113)
-Accrued taxes(194) (137)159
 207
-Accrued compensation(65) (44)(48) (22)
-Retail fuel cost over recovery(84) 1
(76) (104)
-Other current liabilities(6) 16
7
 19
Net cash provided from operating activities482
 1,173
1,411
 1,541
Investing Activities:      
Property additions(1,284) (1,058)(1,211) (947)
Nuclear decommissioning trust fund purchases(271) (386)(174) (275)
Nuclear decommissioning trust fund sales266
 380
174
 275
Cost of removal, net of salvage(32) (34)(82) (70)
Change in construction payables, net of joint owner portion1
 (75)
Payments pursuant to LTSAs(56) (14)
Sale of property63
 
Change in construction payables105
 (37)
Other investing activities(12) 17
(29) (28)
Net cash used for investing activities(1,325) (1,170)(1,217) (1,082)
Financing Activities:      
Increase in notes payable, net37
 39
Proceeds —      
Senior notes550
 400
Capital contributions from parent company380
 239
337
 253
Senior notes850
 650
FFB loan
 300
Short-term borrowings800
 
Redemptions and repurchases —   
Preferred stock250
 
Other long-term debt
 45
Redemptions —

 
Pollution control revenue bonds(27) (4)(36) 
Senior notes(450) (500)(200) (200)
Payment of common stock dividends(640) (653)(536) (574)
Other financing activities(19) (20)(26) (21)
Net cash provided from financing activities931
 51
Net cash provided from (used for) financing activities339
 (97)
Net Change in Cash and Cash Equivalents88
 54
533
 362
Cash and Cash Equivalents at Beginning of Period3
 67
420
 194
Cash and Cash Equivalents at End of Period$91
 $121
$953
 $556
Supplemental Cash Flow Information:      
Cash paid during the period for —   
Interest (net of $11 and $10 capitalized for 2017 and 2016, respectively)$186
 $174
Cash paid (received) during the period for —   
Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively)$217
 $215
Income taxes, net213
 78
146
 (70)
Noncash transactions — Accrued property additions at end of period348
 288
189
 84
The accompanying notes as they relate to GeorgiaAlabama Power are an integral part of these condensed financial statements.

GEORGIAALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $91
 $3
 $953
 $420
Receivables —        
Customer accounts receivable 565
 523
 428
 348
Unbilled revenues 251
 224
 149
 146
Joint owner accounts receivable 199
 57
Other accounts and notes receivable 62
 81
 47
 27
Affiliated 22
 18
 45
 40
Accumulated provision for uncollectible accounts (3) (3) (8) (10)
Fossil fuel stock 330
 298
 171
 205
Materials and supplies 477
 479
 455
 435
Prepaid expenses 55
 105
 58
 34
Other regulatory assets, current 193
 193
 122
 149
Other current assets 22
 38
 5
 11
Total current assets 2,264
 2,016
 2,425
 1,805
Property, Plant, and Equipment:        
In service 34,410
 33,841
 26,619
 26,031
Less: Accumulated provision for depreciation 11,502
 11,317
 9,463
 9,112
Plant in service, net of depreciation 22,908
 22,524
 17,156
 16,919
Nuclear fuel, at amortized cost 559
 569
 314
 336
Construction work in progress 5,422
 4,939
 928
 491
Total property, plant, and equipment 28,889
 28,032
 18,398
 17,746
Other Property and Investments:        
Equity investments in unconsolidated subsidiaries 56
 60
 65
 66
Nuclear decommissioning trusts, at fair value 874
 814
 869
 792
Miscellaneous property and investments 51
 46
 121
 112
Total other property and investments 981
 920
 1,055
 970
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 675
 676
 525
 525
Deferred under recovered regulatory clause revenues 17
 150
Other regulatory assets, deferred 2,790
 2,774
 1,191
 1,157
Other deferred charges and assets 589
 417
 178
 163
Total deferred charges and other assets 4,054
 3,867
 1,911
 1,995
Total Assets $36,188
 $34,835
 $23,789
 $22,516
The accompanying notes as they relate to GeorgiaAlabama Power are an integral part of these condensed financial statements.


GEORGIAALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $261
 $460
 $325
 $561
Notes payable 1,228
 391
Accounts payable —        
Affiliated 367
 438
 275
 297
Other 657
 589
 376
 433
Customer deposits 269
 265
 92
 88
Accrued taxes 212
 407
Accrued taxes —    
Accrued income taxes 115
 45
Other accrued taxes 128
 42
Accrued interest 115
 106
 75
 78
Accrued compensation 141
 224
 151
 193
Asset retirement obligations, current 251
 299
Other regulatory liabilities, current 4
 85
Other current liabilities 185
 297
 50
 76
Total current liabilities 3,686
 3,476
 1,591
 1,898
Long-term Debt 10,793
 10,225
 7,083
 6,535
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 6,163
 6,000
 4,919
 4,654
Deferred credits related to income taxes 118
 121
 60
 65
Accumulated deferred ITCs 251
 256
 118
 110
Employee benefit obligations 652
 703
 289
 300
Asset retirement obligations, deferred 2,340
 2,233
Asset retirement obligations 1,564
 1,503
Other cost of removal obligations 630
 684
Other regulatory liabilities, deferred 93
 100
Other deferred credits and liabilities 206
 199
 51
 63
Total deferred credits and other liabilities 9,730
 9,512
 7,724
 7,479
Total Liabilities 24,209
 23,213
 16,398
 15,912
Preferred Stock 45
 45
Redeemable Preferred Stock 329
 85
Preference Stock 221
 221
 196
 196
Common Stockholder's Equity:        
Common stock, without par value —    
Authorized — 20,000,000 shares    
Outstanding — 9,261,500 shares 398
 398
Common stock, par value $40 per share —    
Authorized — 40,000,000 shares    
Outstanding — 30,537,500 shares 1,222
 1,222
Paid-in capital 7,274
 6,885
 2,961
 2,613
Retained earnings 4,052
 4,086
 2,711
 2,518
Accumulated other comprehensive loss (11) (13) (28) (30)
Total common stockholder's equity 11,713
 11,356
 6,866
 6,323
Total Liabilities and Stockholder's Equity $36,188
 $34,835
 $23,789
 $22,516
The accompanying notes as they relate to GeorgiaAlabama Power are an integral part of these condensed financial statements.

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



SECONDTHIRD QUARTER 2017 vs. SECONDTHIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016


OVERVIEW
GeorgiaAlabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located withinin the State of Georgia andAlabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of GeorgiaAlabama 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. GeorgiaAlabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge GeorgiaAlabama Power for the foreseeable future.
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. 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. 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.
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. 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, and currently expects to include its recommendation in its seventeenth Vogtle Construction Monitoring (VCM) report to be filed with the Georgia PSC in late August 2017.
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. The ultimate outcome of these matters also is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersNuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

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


GeorgiaAlabama 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 after dividends on preferred and preference stock.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(2) (0.6) $(11) (1.8)
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
GeorgiaAlabama Power's net income after dividends on preferred and preference stock for the secondthird quarter 2017 was $347$325 million compared to $349$352 million for the corresponding period in 2016. For year-to-dateThe 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 2017 was $607$729 million compared to $618$721 million for the corresponding period in 2016. The decreases wereincrease was primarily duerelated to an increase in rates under Rate RSE effective January 1, 2017, partially offset by a decrease in retail revenues associated with milder weather asand lower customer usage for year-to-date 2017 compared to the corresponding periodsperiod in 2016, partially offset by lowerand an increase in non-fuel operations and maintenance expenses.
Retail Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(3) (0.2) $(31) (0.9)
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
In the secondthird quarter 2017, retail revenues were $1.90$1.60 billion compared to $1.91$1.63 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $3.59$4.16 billion compared to $3.62$4.14 billion for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
 Second Quarter 2017 Year-to-Date 2017
 (in millions) (% change) (in millions) (% change)
Retail – prior year$1,907
   $3,624
  
Estimated change resulting from –       
Rates and pricing(7) (0.4) 19
 0.5
Sales growth (decline)1
 0.1
 (11) (0.3)
Weather(38) (2.0) (110) (3.1)
Fuel cost recovery41
 2.1
 71
 2.0
Retail – current year$1,904
 (0.2)% $3,593
 (0.9)%
Revenues associated with changes in rates and pricing decreased in the second quarter and increased year-to-date 2017 when compared to the corresponding periods in 2016. An increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff was more than offset in the second quarter 2017 by the rate pricing effect of decreased customer usage and lower contributions from commercial and industrial customers under a rate plan for variable demand-driven pricing. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Constructions" 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 were essentially flat in the second quarter and decreased year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales increased 0.3%, weather-adjusted commercial KWH sales increased 0.4%, and weather-adjusted industrial KWH sales decreased

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1.3%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$1,629
   $4,139
  
Estimated change resulting from –       
Rates and pricing85
 5.2
 240
 5.8
Sales decline(18) (1.1) (31) (0.7)
Weather(50) (3.1) (116) (2.8)
Fuel and other cost recovery(51) (3.1) (77) (1.9)
Retail – current year$1,595
 (2.1)% $4,155
��0.4%
Revenues associated with changes in rates and pricing increased in the second quarter 2017 when compared to the corresponding period in 2016. For year-to-date 2017, weather-adjusted residential KWH sales increased 0.8%, weather-adjusted commercial KWH sales decreased 1.0%, and weather-adjusted industrial KWH sales decreased 2.2% when compared to the corresponding period in 2016. An increase of approximately 29,000 residential customers since June 30, 2016 contributed to the increase in weather-adjusted residential KWH sales. A decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 2,000 commercial customers since June 30, 2016. Decreased demand in the chemicals, paper, and transportation sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, 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.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $41 million and $71 million in the secondthird quarter and year-to-date 2017 respectively, when compared to the corresponding periods in 2016 primarily due to higher natural gas prices, partially offset by lower energyan increase in rates under Rate RSE effective January 1, 2017. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales resulting from milder weather asdecreased in the third quarter and year-to-date 2017 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. Weather-adjusted commercial KWH sales decreased 2.3% and 1.4% for the third quarter and year-to-date 2017, respectively, primarily due to lower 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 increased 1.8% and 0.6% for the third quarter and year-to-date 2017, respectively, as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors, partially offset by a decrease in demand from the pipeline sector.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2016. For the third quarter 2017, the resulting decreases were 5.1% and 2.4% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.8% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a decrease in KWH generation and a decrease in the average cost of fuel. Electric rates include provisions to adjust billings for fluctuations inrecognize the full recovery of fuel costs, including the energy component of purchased power costs.costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery provisions, fuel revenues generally equal fuel and other cost recovery expenses and do not affect net income. 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 PowerMatters" in Item 78 of the Form 10-K for additional information.
OtherWholesale Revenues Affiliates
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$1 1.1 $(11) (5.4)
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$—  $34 69.4
For year-to-date 2017, otherWholesale revenues were $191 million comparedfrom sales to $202 million foraffiliated companies will vary depending on demand and the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenuesavailability and an $8 million decrease in open access transmission tariff revenues, partially offset by a $7 million increase in outdoor lighting sales revenues primarily attributable to LED conversions and a $3 million increase in solar application fee revenue.
Fuel and Purchased Power Expenses
 Second Quarter 2017
vs.
Second Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
 (change in millions) (% change) (change in millions) (% change)
Fuel$6
 1.4 $
 
Purchased power – non-affiliates11
 12.0 16
 9.1
Purchased power – affiliates27
 24.3 60
 24.0
Total fuel and purchased power expenses$44
   $76
  
In the second quarter 2017, total fuel and purchased power expenses were $686 million compared to $642 million in the corresponding period in 2016. The increase was primarily due to a $45 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, slightly offsetgenerating 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 decrease related to the volume of KWHs generated and purchased due to milder weather, resulting in lower customer demand.
For year-to-date 2017, total fuel and purchased power expenses were $1.32 billion compared to $1.24 billion in the corresponding period in 2016. The increase was primarily due to an $89 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 $13 millionsignificant impact on earnings since this energy is generally sold at

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marginal cost and energy purchases are generally 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 million 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 milder weather, resultinga $53 million decrease in lower customer demand.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.
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.

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Details of GeorgiaAlabama Power's generation and purchased power were as follows:
Second Quarter 2017 Second Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017
Year-to-Date 2016
Total generation (in billions of KWHs)
16 17 30 3316 18 46 46
Total purchased power (in billions of KWHs)
6 6 13 122 2 5 6
Sources of generation (percent)
  
Coal36 36 32 3352 59 49 51
Nuclear25 24 25 2424 22 25 24
Gas37 38 41 4019 18 20 19
Hydro2 2 2 35 1 6 6
Cost of fuel, generated (in cents per net KWH)
  
Coal3.20 3.37 3.23 3.452.61 2.73 2.61 2.80
Nuclear0.84 0.84 0.84 0.850.75 0.77 0.75 0.78
Gas2.75 2.18 2.76 2.102.72 2.85 2.74 2.62
Average cost of fuel, generated (in cents per net KWH)(a)
2.43 2.29 2.41 2.262.17 2.32 2.15 2.25
Average cost of purchased power (in cents per net KWH)(*)
4.76 4.45 4.61 4.38
Average cost of purchased power (in cents per net KWH)(b)
5.65 5.70 5.57 4.81
(*)
(a)
KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)
Average cost of purchased power includes fuel, energy, and transmission purchased by GeorgiaAlabama Power for tolling agreements where power is generated by the provider.
Fuel
In the secondthird quarter 2017, fuel expense was $445$343 million compared to $439$410 million infor the corresponding period in 2016. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated by coal, a 4.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 4.4% decrease in average cost of coal per KWH generated. In addition, there was a 194.0% 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 26.2%6.8% decrease in the average cost of coal per KWH generated and a 2.0% 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, partially offset by a 6.1% decrease in the volume of KWHs generated by coal and natural gas. For year-to-date 2017,which excludes fuel expense remained flat compared to the corresponding period in 2016 primarily resulting from a 31.4% increase in the average cost of natural gas per KWH generated, offset by a 9.5% decrease in the volume of KWHs generated by coal and natural gas.associated with tolling agreements.
Purchased Power – Non-AffiliatesAffiliates
In the secondthird quarter 2017, purchased power expense from non-affiliatesaffiliates was $103$55 million compared to $92$41 million infor 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 non-affiliatesaffiliates was $191$117 million compared to $175$129 million infor the corresponding period in 2016. The increases weredecrease was primarily related to a 26.6% decrease in the amount of energy purchased due to increasesa decrease in demand as a result of milder weather in 2017, partially offset by a 22.9% increase in the volume of KWHs purchased of 13.4% and 11.6% in the second quarter and year-to-date 2017, respectively, due to unplanned outages at Georgia Power-owned generating units.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to theaverage cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availabilitypurchased power per KWH as a result of the Southern Company system's generation.higher natural gas prices.

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Purchased Power – Affiliates
In the second quarter 2017, purchased power expense from affiliates was $138 million compared to $111 million in the corresponding period in 2016. The increase was primarily the result of an 11.1% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices and a 5.9% increase in the volume of KWHs purchased due to unplanned outages at Georgia Power-owned generating units and to support Southern Company system transmission reliability.
For year-to-date 2017, purchased power expense from affiliates was $310 million compared to $250 million in the corresponding period in 2016. The increase was primarily the result of a 10.1% increase in the volume of KWHs purchased due to unplanned outages at Georgia Power-owned generating units and to support Southern Company system transmission reliability and an 8.8% increase in the average cost per KWH purchased primarily resulting from higher 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 purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(40) (9.1) $(115) (12.8)
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
In the secondthird quarter 2017, other operations and maintenance expenses were $399$391 million compared to $439$348 million infor the corresponding period in 2016. The decreaseincrease was primarily due to cost containment activities implemented in the third quarter 2016 that contributed to decreasesincreases of $14$26 million in generation maintenance costs and $9 million in transmission and distribution overhead line maintenance. Other factors include decreases of $9 million in customer accounts, service, and sales costs, $5 million in transmission station expenses, and $5 million in billing adjustments with integrated transmission system owners, partially offset by a $7 million increase in scheduled generation outage costs, $11 million in vegetation management costs, and $3 million in employee compensation and benefit costs, including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $781 million$1.13 billion compared to $896 million in the corresponding period in 2016. The decrease was primarily due to cost containment activities implemented in the third quarter 2016 that contributed to decreases of $28 million in generation maintenance costs, $18 million in transmission and distribution maintenance costs, and $13 million in employee benefit costs. Other factors include a $19 million increase in gains from sales of integrated transmission system assets and a $14 million decrease in customer assistance expenses primarily in demand-side management costs related to the timing of new programs.
Depreciation and Amortization
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$9 4.2 $19 4.5
In the second quarter 2017, depreciation and amortization was $223 million compared to $214 million in$1.10 billion for the corresponding period in 2016. The increase was primarily due to aincreases of $31 million in vegetation management costs, $10 million in nuclear generation plant improvement costs, and $7 million increase related to additional plant in serviceemployee compensation and a $4benefit 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, depreciation and amortization of regulatory liabilities relatedwas $185 million compared to other cost of removal obligations that expired$177 million for the corresponding period in December 2016.
For year-to-date 2017, depreciation and amortization was $444$549 million compared to $425$524 million for the corresponding period in 2016. These increases were primarily due to additional plant in service 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. 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 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)
$(3) (1.4) $31 6.7
For year-to-date 2017, income taxes were $493 million compared to $462 million for the corresponding period in 2016. The increase was primarily due to a $17 million increasehigher pre-tax earnings, unrecognized tax benefits related to additional plant in service and a $7 million decrease in amortization of regulatory liabilities related to other cost of removal obligations

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that expired in December 2016, partially offset by a $5 million decrease in depreciation related to generating unit retirements in 2016.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$5 5.1 $12 6.2
In the second quarter 2017, interest expense, net of amounts capitalized was $104 million compared to $99 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $205 million compared to $193 million in the corresponding period in 2016. The increases were primarily due to senior notes issuances and additional long-term borrowings from the FFB.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" hereincertain state deductions for additional information on borrowings from the FFB.
Other Income (Expense), Net
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$8 100.0 $10 38.5
In the second quarter 2017, other income (expense), net was $16 million compared to $8 million in the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $36 million compared to $26 million in the corresponding period in 2016. The increases were primarily due to increases in gains on purchases of state tax credits.
Income Taxes
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(12) (5.7) $(16) (4.3)
In the second quarter 2017,federal income taxes, were $199 million compared to $211 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $355 million compared to $371 million in the corresponding period in 2016. The decreases were primarily due to increased state ITCs and lower pre-tax earnings.prior year tax return actualization.
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. Completing the cost assessments and determining future actions related to 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

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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.transactions. 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

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driven by economic growth. Thethe pace of economic growth and electricity demandthat 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 GeorgiaAlabama 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
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. 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, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of GeorgiaAlabama Power in Item 7 and Note 3 to the financial statements of GeorgiaAlabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's 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. 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 GeorgiaAlabama 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 June 6,September 18, 2017, the EPA proposedpublished 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.

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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 GeorgiaAlabama 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

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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 GeorgiaAlabama 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 GeorgiaAlabama 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 GeorgiaAlabama Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including GeorgiaAlabama Power's) and Southern Power's market power proceeding itrelated 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, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Alabama 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 Alabama 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 matters 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 for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail RegulatoryCondensed Financial Statements herein.
Other Matters – Fuel Cost Recovery" of Georgia
Alabama Power is involved in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgiavarious other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power in Item 7 of the Form 10-K for additional information regarding renewable energy projects.
On May 16, 2017, the Georgia PSC approved Georgia Power's requestis subject to build, own,certain claims 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 six months ended June 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 servicelegal actions arising in the fourth quarter 2017.
The ultimate outcomeordinary course of these matters cannot be determined at this time.business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the 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.

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Integrated Resource PlanThe 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.
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.
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.
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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from 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. The majority of Alabama 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. 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 standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama 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-

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effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may 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 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 income statement outside 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. 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 income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a 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 adoption of ASU 2017-12 is not expected to have a material impact on Alabama Power's financial statements.
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. 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 billion for the first nine months of 2017, a decrease of $130 million as compared to the first nine months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation. Net cash used for investing activities totaled $1.2 billion for the first nine months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $339 million for the first nine months of 2017 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. 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 2017 include increases of $652 million in property, plant, and equipment primarily due to additions to distribution, transmission, and steam generation, $548 million in long-term debt primarily due to the issuance 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

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accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the September 2017 issuance, as well as a decrease of $236 million in securities due within one year.
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. Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017. No additional funds will be required through September 30, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Environmental Matters – Integrated Resource Plan"Environmental Statutes and Regulations – General" and " – Global Climate Issues" of GeorgiaAlabama Power in Item 7 of the Form 10-K for additional information regarding Georgiaon Alabama Power's triennial Integrated Resource Plan.environmental compliance strategy.
On March 7, 2017,Alabama Power's Board of Directors approved its construction program that is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. 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 billion for 2018, $0.1 billion for 2019, $0.2 billion for 2020, $0.3 billion for 2021, and $0.3 billion for 2022. These estimated expenditures do not include any potential compliance costs that may arise from the Georgia PSC approved GeorgiaEPA's final rules and guidelines or future state plans that would limit CO2 emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units.
Alabama Power also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in Alabama Power's decisionasset retirement obligation liabilities. These costs, which could change as Alabama Power continues to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecastsrefine its assumptions underlying the cost estimates and lower fuel costs. Theevaluate the method and timing of recoverycompliance activities, are estimated to be $27 million for costs incurred of approximately $502018, $101 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.
Nuclear Construction
for 2019, $105 million for 2020, $107 million for 2021, and $109 million for 2022. See Note 31 to the financial statements of GeorgiaAlabama Power under "Retail Regulatory Matters – Nuclear Construction""Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regardinginformation. 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 Plant Vogtle Units 3numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and 4, VCM reports,regulations; the NCCR tariff,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 Contractor Settlement Agreement.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, 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At September 30, 2017, Alabama Power had approximately $953 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
Expires     Expires Within One Year
2018 2020 2022 Total Unused Term Out No Term Out
(in millions)
$35
 $500
 $800
 $1,335
 $1,335
 $
 $35
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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, 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. At September 30, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.

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Details of commercial paper 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
(*)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.
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, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$1
At BBB- and/or Baa3$2
Below BBB- and/or Baa3$338
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or 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 Alabama Power 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 credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In February 2017, Alabama Power repaid at maturity $200 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% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness 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).

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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, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
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.

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 the 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 (i) 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, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extentprovided. The Interim Assessment Agreement, as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power,amended, expired on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of theJuly 27, 2017.

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completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
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 July 31,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 $400$386 million, of which $354$340 million had been paid or accrued as of JuneSeptember 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183$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 June 23,August 10, 2017, Toshiba released a revised outlookits financial results for fiscal year 2016,the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $5$4.5 billion as of March 31, 2017, and announced that its independent audit process was continuing.June 30, 2017. Toshiba has alsopreviously 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'sSouthern Company'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 the 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.

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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.

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Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into 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 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 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 JuneSeptember 30, 2017, Georgia Power had recovered approximately $1.4$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

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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$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 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.
Under the terms of the Vogtle Cost Settlement Agreement, the Georgia PSC will determine, for retail ratemaking purposes, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC has approved fifteensixteen VCM reports covering the periods through June 30,December 31, 2016, including construction capital costs incurred, which through that date totaled $3.7$3.9 billion. Georgia Power filed its sixteenthseventeenth VCM report, covering the period from JulyJanuary 1 through December 31, 2016,June 30, 2017, requesting approval of $222$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 27, 2017.6, 2018.
The ultimate outcome of these matters cannot be determined at this time.

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Revised Cost and Schedule
Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. Georgia Power's preliminary assessment results indicate that itsapproximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 rangesis as follows:
Preliminary in-service dates   
Unit 3February 2021March 2022
Unit 4February 2022March 2023
 (in billions)
Preliminary estimated cost to complete$3.9
$4.6
CWIP as of June 30, 20174.5
 4.5
Guarantee Obligations(1.7) (1.7)
Estimated capital costs$6.7
$7.4
Vogtle Cost Settlement Agreement Revised Forecast(5.7) (5.7)
Estimated net additional capital costs$1.0
$1.7
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
 (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 $3.1 billion to $3.5$3.4 billion, of which approximately $1.4$1.5 billion had been incurred through JuneSeptember 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs to cancel both units is approximately $400$350 million. As a result, as of JuneSeptember 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:
Preliminary Cancellation Cost EstimateCancellation Cost Estimate
(in billions)(in billions)
CWIP as of June 30, 2017$4.5
CWIP as of September 30, 2017$4.6
Financing costs collected, net of tax1.4
1.5
Cancellation costs(*)
0.4
0.4
Total$6.3
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, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.recovery.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.

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Other Matters
As of JuneSeptember 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOELoan 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.

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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.
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.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
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
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. 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 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.

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Southern Power
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate 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 result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as 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 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 January 20, 2017, a purported 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 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 defendants Southern Company, certain of its directors, 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' 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

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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 behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees 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 consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
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 investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date 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" herein for additional information on the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
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, and Rate Recovery" of Southern Company 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 project completion date are no longer considered significant accounting estimates. Significant accounting estimates

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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, 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.
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 the impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
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.
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. The new standard also requires enhanced disclosures 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 defined

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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, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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 other 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 component 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 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

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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. Southern Company is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company's financial statements.
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. 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 billion for the first nine months of 2017, an increase of $1.0 billion from the corresponding period in 2016. 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 by the timing of vendor payments. Net cash used for investing activities totaled $6.7 billion for the first nine months of 2017 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. Net cash provided from financing activities totaled $1.3 billion for the first nine months of 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2017 include an increase of $1.3 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, largely offset by the $2.9 billion write-down of the gasification portions of the Kemper IGCC; 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 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $0.7 billion in total common stockholder's equity primarily related to the estimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock.
At the end of the third quarter 2017, the market price of Southern Company's common stock was $49.14 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book ratio of 205%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the third quarter 2017 was $0.58 per share compared to $0.56 per share in the third quarter 2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative

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obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Subsequent 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 $3.2 billion will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes 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) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear 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.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. In addition, Southern Power 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) 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, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On 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.

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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 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 regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of September 30, 2017, Southern Company's current liabilities exceeded current assets by $3.4 billion due to long-term debt that is due within one year of $3.5 billion (comprised of approximately $1.0 billion at the parent company, $0.3 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power) and notes payable of $2.6 billion (comprised of approximately $1.1 billion at the parent company, $0.4 billion at Georgia Power, $0.1 billion at Southern Power, and $0.9 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At September 30, 2017, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
 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.

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See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the 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, 2017 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. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 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 of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
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.

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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 $1,725
 1.5% $1,895
 1.5% $2,284
Short-term bank debt 854
 2.0% 938
 2.1% 1,017
Total $2,579
 1.7% $2,833
 1.7%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.
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, 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.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$38
At BBB- and/or Baa3$647
At BB+ and/or Ba1(*)
$2,352
(*)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, Moody's revised its rating outlook for Mississippi Power from under review to stable.

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Financing Activities
During the first nine months of 2017, Southern Company issued approximately 10.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $479 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 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 million, net of $1.1 million in fees and commissions.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2017:
Company
Senior
Note Issuances
 
Senior
Note Maturities and Redemptions
 
Revenue
Bond
Maturities, Redemptions, and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt Redemptions
and
Maturities(a)
 (in millions)
Southern Company(b)
$300
 $400
 $
 $500
 $400
Alabama Power550
 200
 36
 
 
Georgia Power1,350
 450
 65
 370
 13
Gulf Power300
 85
 
 6
 
Mississippi Power
 
 
 40
 893
Southern Power
 
 
 43
 4
Southern Company Gas(c)
450
 
 
 200
 22
Other
 
 
 
 12
Elimination(d)

 
 
 (40) (599)
Southern Company Consolidated$2,950
 $1,135
 $101
 $1,119
 $745
(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 and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 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 used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.

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Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
Except as described herein, Southern Company's subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs.
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 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.
Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
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 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.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage

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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.
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.

PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the nine months ended September 30, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to 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) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, 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 2017 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.

ALABAMA POWER COMPANY

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 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$1,595
 $1,629
 $4,155
 $4,139
Wholesale revenues, non-affiliates77
 82
 210
 211
Wholesale revenues, affiliates18
 18
 83
 49
Other revenues50
 56
 158
 162
Total operating revenues1,740
 1,785
 4,606
 4,561
Operating Expenses:       
Fuel343
 410
 944
 973
Purchased power, non-affiliates57
 63
 132
 139
Purchased power, affiliates55
 41
 117
 129
Other operations and maintenance391
 348
 1,134
 1,097
Depreciation and amortization185
 177
 549
 524
Taxes other than income taxes93
 96
 284
 286
Total operating expenses1,124
 1,135
 3,160
 3,148
Operating Income616
 650
 1,446
 1,413
Other Income and (Expense):       
Allowance for equity funds used during construction11
 7
 27
 23
Interest expense, net of amounts capitalized(76) (77) (229) (224)
Other income (expense), net(5) (5) (8) (16)
Total other income and (expense)(70) (75) (210) (217)
Earnings Before Income Taxes546
 575
 1,236
 1,196
Income taxes216
 219
 493
 462
Net Income330
 356
 743
 734
Dividends on Preferred and Preference Stock5
 4
 14
 13
Net Income After Dividends on Preferred and Preference Stock$325
 $352
 $729
 $721

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$330
 $356
 $743
 $734
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
Total other comprehensive income (loss)1
 1
 3
 1
Comprehensive Income$331
 $357
 $746
 $735
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 part of these condensed financial statements.

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
  (in millions)
Current Liabilities:    
Securities due within one year $325
 $561
Accounts payable —    
Affiliated 275
 297
Other 376
 433
Customer deposits 92
 88
Accrued taxes —    
Accrued income taxes 115
 45
Other accrued taxes 128
 42
Accrued interest 75
 78
Accrued compensation 151
 193
Other regulatory liabilities, current 4
 85
Other current liabilities 50
 76
Total current liabilities 1,591
 1,898
Long-term Debt 7,083
 6,535
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 4,919
 4,654
Deferred credits related to income taxes 60
 65
Accumulated deferred ITCs 118
 110
Employee benefit obligations 289
 300
Asset retirement obligations 1,564
 1,503
Other cost of removal obligations 630
 684
Other regulatory liabilities, deferred 93
 100
Other deferred credits and liabilities 51
 63
Total deferred credits and other liabilities 7,724
 7,479
Total Liabilities 16,398
 15,912
Redeemable Preferred Stock 329
 85
Preference Stock 196
 196
Common Stockholder's Equity:    
Common stock, par value $40 per share —    
Authorized — 40,000,000 shares    
Outstanding — 30,537,500 shares 1,222
 1,222
Paid-in capital 2,961
 2,613
Retained earnings 2,711
 2,518
Accumulated other comprehensive loss (28) (30)
Total common stockholder's equity 6,866
 6,323
Total Liabilities and Stockholder's Equity $23,789
 $22,516
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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


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 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.
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
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $325 million compared to $352 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 2017 was $729 million compared to $721 million for the corresponding period in 2016. The increase was primarily related to an increase in rates under Rate RSE effective January 1, 2017, partially offset by a decrease in retail revenues associated with milder weather and lower customer usage for year-to-date 2017 compared to the corresponding period in 2016, and an increase in non-fuel operations and maintenance expenses.
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
In the third quarter 2017, retail revenues were $1.60 billion compared to $1.63 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $4.16 billion compared to $4.14 billion for the corresponding period in 2016.

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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$1,629
   $4,139
  
Estimated change resulting from –       
Rates and pricing85
 5.2
 240
 5.8
Sales decline(18) (1.1) (31) (0.7)
Weather(50) (3.1) (116) (2.8)
Fuel and other cost recovery(51) (3.1) (77) (1.9)
Retail – current year$1,595
 (2.1)% $4,155
��0.4%
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in rates under Rate RSE effective January 1, 2017. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 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. Weather-adjusted commercial KWH sales decreased 2.3% and 1.4% for the third quarter and year-to-date 2017, respectively, primarily due to lower 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 increased 1.8% and 0.6% for the third quarter and year-to-date 2017, respectively, as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors, partially offset by a decrease in demand from the pipeline sector.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2016. For the third quarter 2017, the resulting decreases were 5.1% and 2.4% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.8% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a decrease in KWH generation and a decrease in the average cost of fuel. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
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
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

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marginal cost and energy purchases are generally 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 million 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.
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.

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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 2016
Total generation (in billions of KWHs)
16 18 46 46
Total purchased power (in billions of KWHs)
2 2 5 6
Sources of generation (percent) —
       
Coal52 59 49 51
Nuclear24 22 25 24
Gas19 18 20 19
Hydro5 1 6 6
Cost of fuel, generated (in cents per net KWH) 
       
Coal2.61 2.73 2.61 2.80
Nuclear0.75 0.77 0.75 0.78
Gas2.72 2.85 2.74 2.62
Average cost of fuel, generated (in cents per net KWH)(a)
2.17 2.32 2.15 2.25
Average cost of purchased power (in cents per net KWH)(b)
5.65 5.70 5.57 4.81
(a)
KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)
Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2017, fuel expense was $343 million compared to $410 million for the corresponding period in 2016. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated by coal, a 4.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 4.4% decrease in average cost of coal per KWH generated. In addition, there was a 194.0% 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 cost of coal per KWH generated and a 2.0% 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.

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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
In the third quarter 2017, other operations and maintenance expenses were $391 million compared to $348 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.
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, depreciation and amortization was $185 million compared to $177 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. These increases were primarily due to additional plant in service 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. 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 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)
$(3) (1.4) $31 6.7
For year-to-date 2017, income taxes were $493 million compared to $462 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings, unrecognized tax benefits related to certain state deductions for federal income taxes, and prior year tax return actualization.
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 primarily by customer growth. Earnings will also depend upon

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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. 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
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Alabama 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 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 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 Alabama 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

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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 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 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 Alabama Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Alabama 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 Alabama 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 matters 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 for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the 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.

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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.
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.
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.
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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from 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. The majority of Alabama 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. 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 standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama 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-

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effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may 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 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 income statement outside 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. 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 income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a 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 adoption of ASU 2017-12 is not expected to have a material impact on Alabama Power's financial statements.
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. 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 billion for the first nine months of 2017, a decrease of $130 million as compared to the first nine months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation. Net cash used for investing activities totaled $1.2 billion for the first nine months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $339 million for the first nine months of 2017 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. 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 2017 include increases of $652 million in property, plant, and equipment primarily due to additions to distribution, transmission, and steam generation, $548 million in long-term debt primarily due to the issuance 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

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accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the September 2017 issuance, as well as a decrease of $236 million in securities due within one year.
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. Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017. No additional funds will be required through September 30, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
Alabama Power's Board of Directors approved its construction program that is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. 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 billion for 2018, $0.1 billion for 2019, $0.2 billion for 2020, $0.3 billion for 2021, and $0.3 billion for 2022. 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 limit CO2 emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units.
Alabama Power also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in Alabama Power's asset retirement obligation liabilities. These costs, which could change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $27 million for 2018, $101 million for 2019, $105 million for 2020, $107 million for 2021, and $109 million for 2022. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K 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 statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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, 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At September 30, 2017, Alabama Power had approximately $953 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
Expires     Expires Within One Year
2018 2020 2022 Total Unused Term Out No Term Out
(in millions)
$35
 $500
 $800
 $1,335
 $1,335
 $
 $35
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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, 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. At September 30, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.

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Details of commercial paper 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
(*)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.
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, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$1
At BBB- and/or Baa3$2
Below BBB- and/or Baa3$338
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or 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 Alabama Power 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 credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.
Financing Activities
In February 2017, Alabama Power repaid at maturity $200 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% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness 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).

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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, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.
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.

GEORGIA POWER COMPANY

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

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

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the 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.

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


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.
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 after dividends on preferred and preference stock.
Nuclear Construction
Georgia Power and the Vogtle Owners have been constructing Plant Vogtle Units 3 and 4 since 2009. 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). 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, 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

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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 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.
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. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersNuclear 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.
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)
$(20) (3.3) $(29) (2.4)
Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $580 million compared to $600 million 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 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)
$(138) (5.4) $(169) (2.7)
In the third quarter 2017, retail revenues were $2.40 billion compared to $2.54 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $6.00 billion compared to $6.16 billion for the corresponding period in 2016.

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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$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 increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff. 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 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 7 of the Form 10-K for additional information.

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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)
$(7) (7.0) $(18) (6.0)
In the third quarter 2017, other revenues were $93 million compared to $100 million for the corresponding period in 2016. The decrease was primarily due to a $3 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, and a $3 million decrease in solar application fee revenues, partially offset by a $3 million increase in outdoor lighting sales revenues primarily attributable 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 $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
Fuel and Purchased Power Expenses
 Third Quarter 2017
vs.
Third Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
 (change in millions) (% change) (change in millions) (% change)
Fuel$(93) (16.2) $(93) (6.7)
Purchased power – non-affiliates17
 16.7
 33
 11.9
Purchased power – affiliates19
 13.4
 78
 19.9
Total fuel and purchased power expenses$(57)   $18
  
In the third quarter 2017, total fuel and purchased power expenses were $762 million compared to $819 million in 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. The increase was primarily due to a $97 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 primarily due to milder weather, resulting in lower customer demand.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.

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Details of Georgia Power's generation and purchased power were as follows:
 Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
Total generation (in billions of KWHs)
18 20 48 53
Total purchased power (in billions of KWHs)
7 7 20 19
Sources of generation (percent) —
       
Coal35 44 33 37
Nuclear23 22 24 23
Gas41 34 41 38
Hydro1  2 2
Cost of fuel, generated (in cents per net KWH) 
       
Coal3.08 3.16 3.17 3.32
Nuclear0.84 0.85 0.84 0.85
Gas2.63 2.61 2.71 2.27
Average cost of fuel, generated (in cents per net KWH)
2.38 2.47 2.40 2.34
Average cost of purchased power (in cents per net KWH)(*)
4.68 4.57 4.63 4.46
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2017, fuel expense was $482 million compared to $575 million in the corresponding period in 2016. The decrease was primarily due to a 9.6% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, and a 3.6% decrease in the average cost of 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 billion in the corresponding period in 2016. The decrease was primarily due to an 8.4% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, partially offset by a 19.4% increase in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates
In the third quarter 2017, purchased power expense from non-affiliates was $119 million compared to $102 million in the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $310 million compared to $277 million in the corresponding period in 2016. The increases were primarily due to increases in the volume of KWHs 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. The increase for year-to-date 2017 was partially offset by a 1.5% decrease in the average cost per KWH purchased.
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, purchased power expense from affiliates was $161 million compared to $142 million in the corresponding period in 2016. The increase was primarily due to a 1.5% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 5.6% decrease in the volume of

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KWHs purchased due to the expiration of a PPA in May 2017 and milder weather, resulting in lower customer demand.
For year-to-date 2017, purchased power expense from affiliates was $470 million compared to $392 million in the corresponding period in 2016. The increase was primarily the result of a 4.3% increase in the volume of KWHs purchased to support Southern Company system transmission reliability and due to unplanned outages at Georgia Power-owned generating units and a 5.9% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices.
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 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.
For year-to-date 2017, other operations and maintenance expenses were $1.19 billion compared to $1.39 billion 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 $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. The increase was primarily due to an $8 million increase related to additional plant in service and a $4 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, partially offset by a $5 million decrease in depreciation related to generating unit retirements in 2016.

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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
In the third quarter 2017, interest expense, net of amounts capitalized was $105 million compared to $98 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $310 million compared to $290 million in the corresponding period in 2016. The increases were primarily due to increases in outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" 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)
$(6) (54.5) $6 17.1
In the third quarter 2017, other income (expense), net was $5 million compared to $11 million in 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.
For year-to-date 2017, other income (expense), net was $41 million compared to $35 million in 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. The decreases were primarily due to lower pre-tax earnings and increased state ITCs.
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. Matters related to 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 higher multi-family home construction. 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

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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 Georgia Power in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's 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 Georgia 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 of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

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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 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 matters 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 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 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

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– "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding renewable energy projects.
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.
The ultimate outcome of these matters cannot be determined at this time.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
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 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 the 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 Georgia Power's financial statements. 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.
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, 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%.

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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 the 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 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

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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, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the 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 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 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 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.

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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 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

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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

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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.
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 ifwhile 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 ifwhile 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.
IfWhile 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.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

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TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGeorgia Power or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,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.
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ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
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.
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. The new standard also requires enhanced disclosures 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.
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

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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, 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(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 income statement outside 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. ASU 2017-07 will be applied retrospectively for the presentation of the

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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. Georgia Power is currently evaluating the new standard. 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 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Georgia Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Georgia Power's financial statements.
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 JuneSeptember 30, 2017. 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 $482 million$1.48 billion for the first sixnine months of 2017 compared to $1.17$2.27 billion for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments and fossil fuel stock purchases and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $1.33$1.83 billion for the first sixnine months of 2017 compared to $1.17$1.76 billion for the corresponding period in 2016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $931$617 million for the first sixnine months of 2017 compared to $51$528 million used for financing activities in the

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corresponding period in 2016. The increase in cash provided from financing activities is primarily due to an increase in short-term borrowings, higher issuances of senior notes and higher capital contributions received from Southern Company,junior subordinated notes, and a decrease in maturities of senior notes, partially offset by a decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4.4 and an increase in redemptions of 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 sixnine months of 2017 include an increaseincreases of $1.2 billion in property, plant, and equipment of $857 million to comply with environmental standards and the construction of generation, transmission, and distribution facilities, an increase$1.2 billion in notes payable of $837 millionlong-term debt primarily due to issuances of short-term bank debt, an increasesenior 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 liens related to the EPC Contractor's bankruptcy, and $423 million in paid-in capital of $389 million primarily due to capital contributions received from Southern Company,Company. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Recovery" and an increase in long-term debt of $369 million primarily due to issuances of senior notes." – Nuclear Construction" for additional information regarding Hurricane Irma and the EPC Contractor's bankruptcy, respectively.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $261 million will be required through JuneSeptember 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail"Retail Regulatory MattersNuclear Construction"Construction" for additional information regarding Plant Vogtle Units 3 and 4.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the

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environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. 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 MattersGeorgia PowerNuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.
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, 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, 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 has entered into a loan guarantee agreement (Loanthe Loan Guarantee Agreement)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

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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)Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through JuneAs of September 30, 2017, would allow for borrowings of up to $3.1Georgia Power had borrowed $2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion; however, onFacility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, (LGA Amendment) to clarifywhich provides that further advances are conditioned upon the operationDOE's approval of any agreements entered into in replacement of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under4 Agreement and satisfaction of certain other conditions.
On September 28, 2017, the terms of the LGA Amendment,DOE issued a conditional commitment to Georgia Power will not request any advancesfor up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement unlessAgreement. Final approval and until such time as Georgia Power has completedissuance of these additional loan guarantees by the Cost AssessmentsDOE cannot be assured and made a determinationare subject to continue constructionthe negotiation of Plant Vogtle Units 3definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and 4 and satisfied certainsatisfaction of other conditions related to continuing construction.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 regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At JuneSeptember 30, 2017, Georgia Power's current liabilities exceeded current assets by $1.42 billion.$698 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt ($261 million at JuneSeptember 30, 2017) and the periodic use of short-term debt as a funding source ($1.2 billion400 million at JuneSeptember 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, equity contributions from Southern 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 JuneSeptember 30, 2017, Georgia Power had approximately $91$266 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at JuneSeptember 30, 2017 was $1.75 billion of which $1.73 billion was unused. In May 2017, Georgia Power amended its multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.

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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 JuneSeptember 30, 2017, 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) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of JuneSeptember 30, 2017 was approximately $550 million.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

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credit arrangement. In addition, at JuneSeptember 30, 2017, Georgia Power had $436$509 million of pollution control revenue bonds outstanding that were required to be reofferedremarketed 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 is included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
 
Short-term Debt at
June 30, 2017
 
Short-term Debt During the Period(*)
 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
 
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 $428
 1.5% $280
 1.4% $760
 $
 % $109
 1.5% $428
Short-term bank debt 800
 2.0% 227
 2.0% 800
 400
 2.0% 568
 2.0% 800
Total $1,228
 1.8% $507
 1.6%   $400
 2.0% $677
 2.0%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended JuneSeptember 30, 2017.
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 JuneSeptember 30, 2017, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and transmission, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.

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transmission.
The maximum potential collateral requirements under these contracts at JuneSeptember 30, 2017 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$1,210
$1,021
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or 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 Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
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 Georgia Power) from stable to negative.

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On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In March 2017, Georgia Power issued $450 million aggregate principal amount of 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.
In April 2017, Georgia Power purchased and held $27 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 may reofferremarketed these bonds to the public at a later date.public.
In June 2017, Georgia Power repaid at maturity $450 million aggregate principal amount of Series 2007B 5.70% Senior Notes.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, which mature onwith maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, andwhich 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 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.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

GULF POWER COMPANY

GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017
2016 2017 20162017
2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$318
 $319
 $596
 $602
$375
 $377
 $972
 $978
Wholesale revenues, non-affiliates12
 15
 30
 31
14
 17
 44
 48
Wholesale revenues, affiliates10
 15
 47
 36
28
 23
 75
 59
Other revenues17
 16
 34
 31
20
 19
 53
 51
Total operating revenues357
 365
 707
 700
437
 436
 1,144
 1,136
Operating Expenses:              
Fuel88
 107
 196
 201
127
 141
 323
 342
Purchased power, non-affiliates35
 32
 67
 62
37
 33
 104
 95
Purchased power, affiliates9
 4
 11
 5
2
 3
 13
 9
Other operations and maintenance87
 77
 171
 155
81
 86
 252
 239
Depreciation and amortization35
 42
 53
 80
42
 49
 95
 129
Taxes other than income taxes28
 29
 55
 58
33
 34
 88
 93
Loss on Plant Scherer Unit 3
 
 33
 

 
 33
 
Total operating expenses282
 291
 586
 561
322
 346
 908
 907
Operating Income75
 74
 121
 139
115
 90
 236
 229
Other Income and (Expense):              
Interest expense, net of amounts capitalized(13) (12) (24) (25)(13) (11) (37) (36)
Other income (expense), net(1) (1) (2) (2)1
 (2) 
 (4)
Total other income and (expense)(14) (13) (26) (27)(12) (13) (37) (40)
Earnings Before Income Taxes61
 61
 95
 112
103
 77
 199
 189
Income taxes24
 24
 38
 44
40
 30
 78
 74
Net Income37
 37
 57
 68
63
 47
 121
 115
Dividends on Preference Stock2
 3
 4
 5

 2
 4
 7
Net Income After Dividends on Preference Stock$35
 $34
 $53
 $63
$63
 $45
 $117
 $108
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Net Income$37
 $37
 $57
 $68
$63
 $47
 $121
 $115
Other comprehensive income (loss):              
Qualifying hedges:              
Changes in fair value, net of tax of
$-, $(1), $(1), and $(3), respectively
(1) (1) (1) (4)
Changes in fair value, net of tax of $-, $-, $(1), and $(3), respectively
 
 (1) (4)
Total other comprehensive income (loss)(1) (1) (1) (4)
 
 (1) (4)
Comprehensive Income$36
 $36
 $56
 $64
$63
 $47
 $120
 $111
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Six Months Ended June 30,For the Nine Months Ended September 30,
2017 20162017 2016
(in millions)(in millions)
Operating Activities:      
Net income$57
 $68
$121
 $115
Adjustments to reconcile net income to net cash provided from operating activities —      
Depreciation and amortization, total56
 83
100
 134
Deferred income taxes19
 16
57
 15
Loss on Plant Scherer Unit 333
 
33
 
Other, net(4) (3)(5) (2)
Changes in certain current assets and liabilities —      
-Receivables(25) (6)(65) (9)
-Fossil fuel stock4
 34
7
 49
-Other current assets10
 1
11
 3
-Accrued taxes7
 17
21
 40
-Accrued compensation(17) (12)(10) (5)
-Over recovered regulatory clause revenues(19) 5
(8) 26
-Other current liabilities3
 (7)10
 8
Net cash provided from operating activities124
 196
272
 374
Investing Activities:      
Property additions(97) (68)(142) (106)
Cost of removal, net of salvage(9) (4)(16) (8)
Change in construction payables(14) (7)(9) (7)
Other investing activities(3) (5)(6) (6)
Net cash used for investing activities(123) (84)(173) (127)
Financing Activities:      
Increase (decrease) in notes payable, net(190) 46
Decrease in notes payable, net(268) (42)
Proceeds —      
Common stock issued to parent175
 
175
 
Capital contributions from parent company5
 5
7
 10
Senior notes300
 
300
 
Redemptions —      
Preference stock(150) 
(150) 
Senior notes(85) (125)(85) (125)
Payment of common stock dividends(63) (60)(94) (90)
Other financing activities(4) (6)(3) (5)
Net cash used for financing activities(12) (140)(118) (252)
Net Change in Cash and Cash Equivalents(11) (28)(19) (5)
Cash and Cash Equivalents at Beginning of Period56
 74
56
 74
Cash and Cash Equivalents at End of Period$45
 $46
$37
 $69
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —   
Cash paid during the period for —   
Interest (net of $- and $- capitalized for 2017 and 2016, respectively)$22
 $28
$24
 $29
Income taxes, net7
 (3)19
 14
Noncash transactions — Accrued property additions at end of period19
 13
25
 13
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $45
 $56
 $37
 $56
Receivables —        
Customer accounts receivable 77
 72
 96
 72
Unbilled revenues 70
 55
 68
 55
Under recovered regulatory clause revenues 26
 17
 15
 17
Income taxes receivable, current 15
 
Other accounts and notes receivable 11
 6
 12
 6
Affiliated 8
 17
 13
 17
Accumulated provision for uncollectible accounts (1) (1) (1) (1)
Fossil fuel stock 67
 71
 64
 71
Materials and supplies 57
 55
 58
 55
Other regulatory assets, current 55
 44
 55
 44
Other current assets 17
 30
 15
 30
Total current assets 432
 422
 447
 422
Property, Plant, and Equipment:        
In service 5,156
 5,140
 5,181
 5,140
Less: Accumulated provision for depreciation 1,427
 1,382
 1,457
 1,382
Plant in service, net of depreciation 3,729
 3,758
 3,724
 3,758
Construction work in progress 59
 51
 75
 51
Total property, plant, and equipment 3,788
 3,809
 3,799
 3,809
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 57
 58
 56
 58
Other regulatory assets, deferred 510
 512
 499
 512
Other deferred charges and assets 22
 21
 22
 21
Total deferred charges and other assets 589
 591
 577
 591
Total Assets $4,809
 $4,822
 $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 June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $27
 $87
 $7
 $87
Notes payable 78
 268
 
 268
Accounts payable —        
Affiliated 52
 59
 46
 59
Other 46
 54
 55
 54
Customer deposits 35
 35
 35
 35
Accrued taxes 27
 20
 41
 20
Accrued interest 9
 8
 20
 8
Accrued compensation 23
 40
 30
 40
Deferred capacity expense, current 22
 22
 22
 22
Other regulatory liabilities, current 
 16
 1
 16
Other current liabilities 43
 40
 37
 40
Total current liabilities 362
 649
 294
 649
Long-term Debt 1,265
 987
 1,285
 987
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 966
 948
 1,003
 948
Employee benefit obligations 92
 96
 90
 96
Deferred capacity expense 108
 119
 103
 119
Asset retirement obligations, deferred 125
 120
 125
 120
Other cost of removal obligations 218
 249
 218
 249
Other regulatory liabilities, deferred 46
 47
 45
 47
Other deferred credits and liabilities 74
 71
 71
 71
Total deferred credits and other liabilities 1,629
 1,650
 1,655
 1,650
Total Liabilities 3,256
 3,286
 3,234
 3,286
Preference Stock 
 147
 
 147
Common Stockholder's Equity:        
Common stock, without par value —        
Authorized — 20,000,000 shares        
Outstanding — June 30, 2017: 7,392,717 shares    
Outstanding — September 30, 2017: 7,392,717 shares    
— December 31, 2016: 5,642,717 shares 678
 503
 678
 503
Paid-in capital 596
 589
 600
 589
Retained earnings 280
 296
 312
 296
Accumulated other comprehensive income (loss) (1) 1
 (1) 1
Total common stockholder's equity 1,553
 1,389
 1,589
 1,389
Total Liabilities and Stockholder's Equity $4,809
 $4,822
 $4,823
 $4,822
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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SECONDTHIRD QUARTER 2017 vs. SECONDTHIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016


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.
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 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.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. UnderAmong 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 consistsconsisted 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 by the Florida PSC in November 2016.
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.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$1 2.9 $(10) (15.9)
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
Gulf Power's net income after dividends on preference stock for the secondthird quarter 2017 was $35$63 million compared to $34$45 million for the corresponding period in 2016. The increase was primarily due to an increase in retail base revenues and a decrease in depreciation.
Gulf Power's net income after dividends on preference stock for year-to-date 2017 was $53$117 million compared to $63$108 million for the corresponding period in 2016. The decrease for year-to-date 2017increase was primarily due to a decrease in depreciation and

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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, partially offset by lower depreciation and higher wholesale revenue.expenses. See Note (B) to the

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
Retail Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
Third Quarter 2017 vs. Third Quarter 2016Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change) (% change) (change in millions) (% change)
$(1)(2) (0.3) $(6) (1.0) (0.5) $(6) (0.6)
In the secondthird quarter 2017, retail revenues were $318$375 million compared to $319$377 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $596$972 million compared to $602$978 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
Second Quarter 2017 Year-to-Date 2017Third Quarter 2017 Year-to-Date 2017
(in millions) (% change) (in millions) (% change)(in millions) (% change) (in millions) (% change)
Retail – prior year$319
   $602
  $377
   $978
  
Estimated change resulting from –              
Rates and pricing5
 1.6
 7
 1.2
21
 5.6
 28
 2.9
Sales decline(1) (0.3) (3) (0.5)
Sales growth3
 0.8
 1
 0.1
Weather
 
 (6) (1.0)(9) (2.4) (14) (1.4)
Fuel and other cost recovery(5) (1.6) (4) (0.7)(17) (4.5) (21) (2.2)
Retail – current year$318
 (0.3)% $596
 (1.0)%$375
 (0.5)% $972
 (0.6)%
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increased in the secondthird quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in retail base revenues effective July 2017, as well as an increase in environmental cost recovery effective November 2016 resulting from Gulf Power's ownership of Plant Scherer Unit 3 being rededicated to retail service.
Revenues attributable to changes in sales decreasedincreased slightly in the secondthird quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjustedFor the third quarter 2017, 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 primarily due to customer growth, partially offset by lower customer usage primarily resulting from efficiency improvements in appliances and lighting. Weather-adjusted KWH sales to commercial customers decreased 1.2% and 1.3%, respectively, for the second quarter 2017 and 1.3% and 1.0%, respectively, forslightly year-to-date 2017 due toas a result of lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partiallymostly offset by customer growth. KWH sales to industrial customers decreased 2.7%7.1% and 5.6%6.1% for the secondthird quarter and year-to-date 2017, respectively, primarily due to changes in customers' operations. The year-to-date 2017 decrease also reflects increased customer co-generation.operations and energy efficiency improvements.
Fuel and other cost recovery revenues decreased in the secondthird quarter and year-to-date 2017 when compared to the corresponding periods in 2016, primarily due to lower fuel, purchased power capacity, and energy conservation recoverable costs, partially offset by higher environmental recoverable costs. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

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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 Rate Case Settlement Agreement. 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 cost recovery clauses and Note (B) to the Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base Rate Cases" herein for additional information regarding the 2017 Rate Case 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
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(5) (33.3) $11 30.6
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
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 secondthird quarter 2017, wholesale revenues from sales to affiliates were $10$28 million compared to $15 million for the corresponding period in 2016. The decrease was primarily due to a 40.6% decrease in KWH sales due to decreased generation as a result of milder weather reducing Southern Company system loads.
For year-to-date 2017, wholesale revenues from sales to affiliates were $47 million compared to $36$23 million for the corresponding period in 2016. The increase was primarily due to a 17.2%24.1% increase in KWH sales resulting from outages of affiliate generation resources.
For year-to-date 2017, wholesale revenues from sales to affiliates were $75 million compared to $59 million for the corresponding period in 2016. The increase was primarily due to a 19.5% increase in KWH sales as a result of supporting Southern Company system transmission reliability and a 10.0% increase in the priceavailability of energy due to higher natural gas prices.lower-cost Gulf Power generation resources.

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Fuel and Purchased Power Expenses
Second Quarter 2017
vs.
Second Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
Third Quarter 2017
vs.
Third Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$(19) (17.8) $(5) (2.5)$(14) (9.9) $(19) (5.6)
Purchased power – non-affiliates3
 9.4
 5
 8.1
4
 12.1
 9
 9.5
Purchased power – affiliates5
 125.0
 6
 120.0
(1) (33.3) 4
 44.4
Total fuel and purchased power expenses$(11)   $6
  $(11)   $(6)  
In the secondthird quarter 2017, total fuel and purchased power expenses were $132$166 million compared to $143$177 million for the corresponding period in 2016. The decrease was primarily the result of a $21$7 million net decrease due to the lower average cost of fuel and a $6 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand.
For year-to-date 2017, total fuel and purchased power expenses were $440 million compared to $446 million for the corresponding period in 2016. The decrease was primarily the result of a $19 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand, partially offset by an $11 million net increase due to the higher average cost of fuel associated with purchased power.
For year-to-date 2017, total fuel and purchased power expenses were $274 million compared to $268 million for the corresponding period in 2016. The increase was primarily the result of a $16$12 million net increase related to the higher average cost of fuel and purchased power resulting from higher natural gas prices, partially offset by a $10 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand.power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.

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Details of Gulf Power's generation and purchased power were as follows:
Second Quarter 2017 Second Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
Total generation (in millions of KWHs)
1,898 2,064 4,220 3,8802,780 2,775 7,000 6,654
Total purchased power (in millions of KWHs)
1,218 1,629 2,676 3,3891,686 1,906 4,362 5,295
Sources of generation (percent)
  
Coal50 54 52 4859 68 55 57
Gas50 46 48 5241 32 45 43
Cost of fuel, generated (in cents per net KWH)
  
Coal3.17 4.14 3.23 4.053.04 3.55 3.15 3.80
Gas3.88 4.11 3.54 3.923.71 4.38 3.60 4.06
Average cost of fuel, generated (in cents per net KWH)
3.53 4.12 3.38 3.983.31 3.81 3.35 3.91
Average cost of purchased power (in cents per net KWH)(*)
5.37 3.50 4.93 3.354.32 3.79 4.70 3.51
(*)Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.
Fuel
In the secondthird quarter 2017, fuel expense was $88$127 million compared to $107$141 million for the corresponding period in 2016. The decrease was primarily due to a 13.1% 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.

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For year-to-date 2017, fuel expense was $323 million compared to $342 million for the corresponding period in 2016. The decrease was primarily due to a 14.3% decrease in the average cost of fuel resulting from lower coal and natural gas prices, and a 15.3% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to milder weather reducing demand.
For year-to-date 2017, fuel expense was $196 million compared to $201 million for the corresponding period in 2016. The decrease was primarily due to a 15.1% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by an 8.8%a 10.3% increase in the volume of KWHs generated by Gulf Power's coal-fired and gas-fired generation resources due to Southern Company system reliability requirements.resources.
Purchased Power – Non-Affiliates
In the secondthird quarter 2017, purchased power expense from non-affiliates was $35$37 million compared to $32$33 million for the corresponding period in 2016. The increase was primarily due to a 68.7% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 37.9% decrease in the volume of KWHs purchased due to a planned outage of an external generation resource under a PPA.
For year-to-date 2017, purchased power expense from non-affiliates was $67$104 million compared to $62$95 million for the corresponding period in 2016. The increase wasThese increases were primarily due to a 50.0% increaseincreases of 16.3% and 35.9% for the third quarter and year-to-date 2017, respectively, in the average cost per KWH purchased, primarily resulting from higher natural gas prices, partially offset by a 25.6% decreasedecreases of 11.1% and 20.2% for the third quarter and year-to-date 2017, respectively, in the volume of KWHs purchased due to a planned outage of an external generation resource under a PPA.lower territorial load.
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 secondthird quarter 2017, purchased power expense from affiliates was $9$2 million compared to $4$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 66.1%13.2% increase in the volume of KWHs purchased due to availability of power pool resources at lower cost compared to Gulf Power generation.
For year-to-date 2017, purchased power expense from affiliates was $11 million compared to $5 millionmore planned outages for the corresponding period in 2016. The increase was primarily due to a 22.9% increase in the volume of KWHs

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purchased due to availability of power pool resources at lower cost compared to Gulf Power generation resources and a 67.1%29.3% increase in the average cost per KWH purchased primarily resulting fromdue 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 purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$10 13.0 $16 10.3
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 secondthird quarter 2017, other operations and maintenance expenses were $87$81 million compared to $77$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 $171$252 million compared to $155$239 million for the corresponding period in 2016. The increases wereincrease 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 MattersGulf PowerRetail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.

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Depreciation and Amortization
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
Third Quarter 2017 vs. Third Quarter 2016Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change) (% change) (change in millions) (% change)
$(7) (16.7) $(27) (33.8) (14.3) $(34) (26.4)
In the secondthird quarter 2017, depreciation and amortization was $35$42 million compared to $42$49 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $53$95 million compared to $80$129 million for the corresponding period in 2016. TheThese decreases were primarily due to $8 million and $28 million more of a reductionchanges in the reductions in depreciation, 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 secondthird quarter and year-to-date 2017, respectively, compared to the corresponding periods in 2016. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base 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 the third quarter 2017, income taxes were $40 million compared to $30 million for the corresponding period 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 result of the redemption of all preference stock in June 2017. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.
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. 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 economic growth. Thethe pace of economic growth and electricity demandthat may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to

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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

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1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such 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, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Gulf 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 June 6,September 18, 2017, the EPA proposedpublished 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 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 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

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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.

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FERC Matters
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 proceeding itrelated 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, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Gulf 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 Gulf 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 matters 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 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. In the first six months ofThrough June 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. UnderAmong 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 consistsconsisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for

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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 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, 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.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting

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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, 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.
Renewables
In 2015, the Florida PSC approved 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.
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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGulf Power or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,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.

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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.
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.
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. The new standard also requires enhanced disclosures 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.

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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, 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(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

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costs to be separately presented in the income statement outside 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. 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. Gulf Power is currently evaluating the new standard. 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 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Gulf Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Gulf Power's financial statements.
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 JuneSeptember 30, 2017. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $124$272 million for the first sixnine months of 2017 compared to $196$374 million for the corresponding period in 2016. The $72$102 million decrease in net cash was primarily due to decreases related to certain cost recovery clauses, the timing of fossil fuel stock purchases, and a federal income tax refund received in 2016, as well as decreases in cash flows associated with lower cost recovery clause rates.2016. Net cash used for investing activities totaled $123$173 million in the first sixnine months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $12$118 million for the first sixnine months of 2017 primarily due to the payment of short-term debt, redemptions of preference stock and long-term debt, and common stock dividend payments, partially offset by proceeds from

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issuances of long-term debt and 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 sixnine months of 2017 primarily reflect the financing activities described above. Other significant changes include an increase in accumulated deferred income taxes due to accelerated depreciation and repair deductions and a decrease in other cost of removal obligations, as authorized in the 2013 Rate Case Settlement Agreement, and a decrease in property, plant, and equipment primarily due to the write-down of Gulf Power's ownership of Plant Scherer Unit 3.Agreement. See "Financing Activities" herein and Note (B) to the Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base Rate Cases" 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 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

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with existing environmental statutes and regulations, 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 JuneSeptember 30, 2018 to fund maturities of long-term debt. In addition, at June 30, 2017, $20 million of Gulf Power's total fixed rate pollution control revenue bonds required to be remarketed over the next 12 months are classified as securities due within one year. See "Financing Activities" herein for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.

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At JuneSeptember 30, 2017, Gulf Power had approximately $45$37 million of cash and cash equivalents. Committed credit arrangements with banks at JuneSeptember 30, 2017 were as follows:
Expires     
Executable Term
Loans
 
Expires Within One
Year
2017 2018 2019 2020 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)
$30
 $195
 $25
 $30
 $280
 $280
 $45
 $
 $
 $40
See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) 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 JuneSeptember 30, 2017, Gulf 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, 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.

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Most of the unused credit arrangements with banks are allocated to provide liquidity support to Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of JuneSeptember 30, 2017 was approximately $82 million. In addition, at JuneSeptember 30, 2017, Gulf Power had approximately $140 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 in the balance sheets.
Details of short-term borrowings were as follows:
  
Short-term Debt at
June 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 $78
 1.5% $20
 1.4% $78
Short-term bank debt 
 % 53
 1.7% 100
Total $78
 1.5% $73
 1.6%  
  
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
(*)Average and maximum amounts are based upon daily balances during the three-month period ended JuneSeptember 30, 2017. No short-term debt was outstanding at September 30, 2017.
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.

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Credit Rating Risk
At JuneSeptember 30, 2017, 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, transmission, and energy price risk management.
The maximum potential collateral requirements under these contracts at JuneSeptember 30, 2017 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$167
$167
Below BBB- and/or Baa3$570
$579
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or 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 Gulf Power 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 credit rating outlook for Southern Company and its subsidiaries (including Gulf Power) from stable to negative.

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Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the secondthird quarter and year-to-date 2017 has not changed materially compared to the December 31, 2016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreement shifts substantially all fuel cost responsibility to the purchaser.
In connection with the 2017 Rate Case Settlement Agreement, 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 throughuntil 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 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.

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In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 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.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

MISSISSIPPI POWER COMPANY

MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$222
 $206
 $422
 $389
$243
 $263
 $665
 $652
Wholesale revenues, non-affiliates62
 60
 124
 120
72
 78
 196
 198
Wholesale revenues, affiliates15
 7
 20
 16
21
 7
 40
 23
Other revenues4
 4
 9
 8
5
 4
 14
 12
Total operating revenues303
 277
 575
 533
341
 352
 915
 885
Operating Expenses:              
Fuel102
 81
 180
 157
120
 112
 301
 268
Purchased power, non-affiliates2
 1
 3
 1
4
 3
 7
 4
Purchased power, affiliates4
 4
 11
 9
2
 5
 13
 14
Other operations and maintenance70
 68
 144
 136
66
 74
 206
 211
Depreciation and amortization41
 45
 81
 84
39
 30
 120
 114
Taxes other than income taxes26
 25
 52
 50
25
 31
 77
 81
Estimated loss on Kemper IGCC3,012
 81
 3,120
 134
34
 88
 3,155
 222
Total operating expenses3,257
 305
 3,591
 571
290
 343
 3,879
 914
Operating Loss(2,954) (28) (3,016) (38)
Operating Income (Loss)51
 9
 (2,964) (29)
Other Income and (Expense):              
Allowance for equity funds used during construction36
 30
 71
 59
1
 31
 72
 90
Interest expense, net of amounts capitalized(17) (15) (37) (31)13
 (15) (23) (46)
Other income (expense), net1
 (1) 1
 (3)(1) (1) (3) (4)
Total other income and (expense)20
 14
 35
 25
13
 15
 46
 40
Loss Before Income Taxes(2,934) (14) (2,981) (13)
Earnings (Loss) Before Income Taxes64
 24
 (2,918) 11
Income taxes (benefit)(881) (17) (908) (27)24
 (2) (885) (29)
Net Income (Loss)(2,053) 3
 (2,073) 14
40
 26
 (2,033) 40
Dividends on Preferred Stock1
 1
 1
 1

 
 1
 1
Net Income (Loss) After Dividends on Preferred Stock$(2,054) $2
 $(2,074) $13
$40
 $26
 $(2,034) $39
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Net Income (Loss)$(2,053) $3
 $(2,073) $14
$40
 $26
 $(2,033) $40
Other comprehensive income (loss)
 
 
 

 
 
 
Qualifying hedges:              
Changes in fair value, net of tax of $-, $-, $-, and $-, respectively
 
 1
 
(1) 
 
 (1)
Reclassification adjustment for amounts included in net
income, net of tax of $-, $-, $-, and $-, respectively

 
 1
 1
Total other comprehensive income (loss)
 
 1
 
(1) 
 1
 
Comprehensive Income (Loss)$(2,053) $3
 $(2,072) $14
$39
 $26
 $(2,032) $40
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 Six Months Ended June 30,For the Nine Months Ended September 30,
2017 20162017 2016
(in millions)(in millions)
Operating Activities:      
Net income (loss)$(2,073) $14
$(2,033) $40
Adjustments to reconcile net income (loss) to net cash provided from operating activities —      
Depreciation and amortization, total94
 82
144
 115
Deferred income taxes(860) (16)(1,159) 34
Allowance for equity funds used during construction(71) (59)(72) (90)
Estimated loss on Kemper IGCC3,120
 134
3,148
 222
Other, net(11) (8)(26) (1)
Changes in certain current assets and liabilities —      
-Receivables(15) 15
438
 3
-Fossil fuel stock21
 6
21
 8
-Other current assets(10) 31
(9) 34
-Accounts payable(20) (12)(21) 5
-Accrued taxes
 20
20
 96
-Accrued compensation(17) (12)(12) (5)
-Over recovered regulatory clause revenues(30) 4
(47) (20)
-Customer liability associated with Kemper refunds
 (69)
 (73)
-Other current liabilities7
 7
(31) 5
Net cash provided from operating activities135
 137
361
 373
Investing Activities:      
Property additions(337) (403)(411) (592)
Construction payables(19) (11)(47) (25)
Government grant proceeds
 137

 137
Other investing activities(5) (19)(25) (29)
Net cash used for investing activities(361) (296)(483) (509)
Financing Activities:      
Decrease in notes payable, net(10) 
(23) 
Proceeds —      
Capital contributions from parent company1,001
 226
1,002
 227
Long-term debt to parent company40
 200
40
 200
Other long-term debt
 900

 900
Short-term borrowings4
 
113
 
Redemptions —      
Short-term borrowings
 (475)(109) (475)
Long-term debt to parent company(591) (225)(591) (225)
Other long-term debt(300) (425)(300) (425)
Other financing activities(2) (3)(3) (5)
Net cash provided from financing activities142
 198
129
 197
Net Change in Cash and Cash Equivalents(84) 39
7
 61
Cash and Cash Equivalents at Beginning of Period224
 98
224
 98
Cash and Cash Equivalents at End of Period$140
 $137
$231
 $159
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —      
Interest (paid $53 and $49, net of $27 and $23 capitalized for 2017
and 2016, respectively)
$26
 $26
Interest (paid $73 and $72, net of $28 and $36 capitalized for 2017
and 2016, respectively)
$45
 $36
Income taxes, net(93) (122)(209) (231)
Noncash transactions — Accrued property additions at end of period59
 94
32
 80
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)
 
Assets At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $140
 $224
 $231
 $224
Receivables —        
Customer accounts receivable 33
 29
 38
 29
Unbilled revenues 42
 42
 41
 42
Income taxes receivable, current 544
 544
 102
 544
Other accounts and notes receivable 25
 14
 15
 14
Affiliated 20
 15
 15
 15
Fossil fuel stock 20
 100
 20
 100
Materials and supplies 44
 76
 45
 76
Other regulatory assets, current 114
 115
 113
 115
Other current assets 2
 8
 8
 8
Total current assets 984
 1,167
 628
 1,167
Property, Plant, and Equipment:        
In service 4,826
 4,865
 4,836
 4,865
Less: Accumulated provision for depreciation 1,283
 1,289
 1,312
 1,289
Plant in service, net of depreciation 3,543
 3,576
 3,524
 3,576
Construction work in progress 56
 2,545
 75
 2,545
Total property, plant, and equipment 3,599
 6,121
 3,599
 6,121
Other Property and Investments 22
 12
 28
 12
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 61
 361
 62
 361
Other regulatory assets, deferred 441
 518
 436
 518
Accumulated deferred income taxes 404
 
 279
 
Other deferred charges and assets 20
 56
 23
 56
Total deferred charges and other assets 926
 935
 800
 935
Total Assets $5,531
 $8,235
 $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 June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year —        
Parent $
 $551
 $
 $551
Other 1,028
 78
 1,028
 78
Notes payable 17
 23
 4
 23
Accounts payable —        
Affiliated 54
 62
 56
 62
Other 109
 135
 82
 135
Customer deposits 16
 16
 16
 16
Accrued taxes 97
 99
 78
 99
Unrecognized tax benefits 385
 383
 2
 383
Accrued interest 52
 46
 16
 46
Accrued compensation 25
 42
 29
 42
Asset retirement obligations, current 21
 32
 15
 32
Over recovered regulatory clause liabilities 21
 51
Over recovered fuel clause liabilities 4
 51
Other current liabilities 89
 20
 67
 20
Total current liabilities 1,914
 1,538
 1,397
 1,538
Long-term Debt 1,169
 2,424
 1,167
 2,424
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 
 756
 
 756
Employee benefit obligations 111
 115
 109
 115
Asset retirement obligations, deferred 149
 146
 150
 146
Other cost of removal obligations 173
 170
 175
 170
Other regulatory liabilities, deferred 80
 84
 87
 84
Other deferred credits and liabilities 29
 26
 23
 26
Total deferred credits and other liabilities 542
 1,297
 544
 1,297
Total Liabilities 3,625
 5,259
 3,108
 5,259
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 4,527
 3,525
 4,529
 3,525
Accumulated deficit (2,689) (616) (2,650) (616)
Accumulated other comprehensive loss (3) (4) (3) (4)
Total common stockholder's equity 1,873
 2,943
 1,914
 2,943
Total Liabilities and Stockholder's Equity $5,531
 $8,235
 $5,055
 $8,235
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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SECONDTHIRD QUARTER 2017 vs. SECONDTHIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016


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 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 (which exists when Mississippi Power demonstrates that the purpose and effect of the construction(construction cost increase isdemonstrated to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). 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) between Mississippi Power and the Mississippi Public Utilities Staff (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 remainder of the plant includes the gasifiers and the gas clean-up facilities. 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. Most recently, inIn 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

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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

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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. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
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 grants from the DOE received on April 8, 2016 (Additional DOE Grants). Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $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.
At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions 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 Order,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.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion$34 million ($2.1 billion21 million after tax) for the secondthird quarter 2017 and $3.1$3.2 billion ($2.2 billion after tax) for the sixnine months ended JuneSeptember 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.94.0 billion after tax) through JuneSeptember 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 JuneSeptember 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

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previously contracted to SMEPA.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.

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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 Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
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 $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.
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""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)
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(2,056) N/M $(2,087) N/M
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
N/M - Not meaningful
InMississippi Power's net income after dividends on preferred stock for the secondthird quarter 2017 was $40 million compared to $26 million for the corresponding period in 2016. The increase was due to lower pre-tax charges associated with the Kemper IGCC and year-to-date 2017, a decrease in interest expense, net of amounts capitalized, partially offset by an increase in income taxes and decreases in retail revenues and AFUDC equity.
Mississippi Power's net loss after dividends on preferred stock for year-to-date 2017 was $2.05$2.03 billion and $2.07 billion, respectively, compared to net income of $2$39 million and $13 million, respectively, for the corresponding periodsperiod in 2016. In the second quarter and year-to-date 2017, theThe decrease in net income was related to higher pre-tax charges associated with the Kemper IGCC of $3.0 billion ($2.1 billion after tax) and $3.1 billion ($2.2 billion after tax), respectively, compared to pre-tax charges of $81 million ($50 million after tax) and $134 million ($83 million after tax), respectively, for the corresponding periods in 2016. The changes in net income were partially offset by a decrease in depreciation and amortization and increases in retail revenues, AFUDC equity, and income tax benefits.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.

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Retail Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$16 7.8 $33 8.5
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
In the secondthird quarter 2017, retail revenues were $222$243 million compared to $206$263 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $422$665 million compared to $389$652 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
Second Quarter 2017 Year-to-Date 2017Third Quarter 2017 Year-to-Date 2017
(in millions) (% change) (in millions) (% change)(in millions) (% change) (in millions) (% change)
Retail – prior year$206
   $389
  $263
   $652
  
Estimated change resulting from –              
Rates and pricing8
 3.9
 19
 4.9
(10) (3.8) 9
 1.4
Sales growth (decline)(2) (0.9) 3
 0.8
Sales growth1
 0.4
 4
 0.6
Weather(2) (1.0) (7) (1.8)(9) (3.4) (16) (2.5)
Fuel and other cost recovery12
 5.8
 18
 4.6
(2) (0.8) 16
 2.5
Retail – current year$222
 7.8 % $422
 8.5 %$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.
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2017 when compared to the corresponding periodsperiod in 2016 primarily due to an ECO Plan rate increase implemented in the third quarter 2016, partially offset by the 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.
See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Revenues attributable to changes in sales decreasedincreased slightly for the secondthird quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers decreased 2.7%increased 2.9% due to lowerhigher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.8%1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 1.3%2.4% primarily due to an unplanned outage 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.
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 andcustomers increased 0.8% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.7% and 0.5%, respectively, due to lower customer usage.usage, partially offset by customer growth. KWH sales to industrial customers decreased 0.4%1.1% primarily due to an unplanned outageoutages by a largerlarge 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 increased in the second quarter and

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for year-to-date 2017 when compared to the corresponding periodsperiod in 2016 primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$2 3.3 $4 3.3
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

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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 second quarter and year-to-date 2017, wholesale revenues from sales to non-affiliates were $62 million and $124 million, respectively, compared to $60 million and $120 million for the corresponding periods in 2016. The increases were due to increases in energy revenues of $4 million and $5 million in the second quarter and year-to-date 2017, respectively, primarily resulting from higher fuel prices, partially offset by decreases in base and capacity revenues of $2 million and $1 million, respectively, primarily due to milder weather resulting in lower sales.
Wholesale Revenues – Affiliates
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$8 N/M $4 25.0
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
N/M - Not meaningful
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the secondthird quarter 2017, wholesale revenues from sales to affiliates were $15$21 million compared to $7 million for the corresponding period in 2016. The increase was due to a $6$13 million increase in KWH sales as a result of supporting Southern Company system transmission reliability and a $2$1 million increase primarily due to higher natural gas prices.
For year-to-date 2017, wholesale revenues from sales to affiliates were $20$40 million compared to $16$23 million for the corresponding period in 2016. The increase was primarily due to higher KWH sales as a result of supporting Southern Company system transmission reliability and higher natural gas prices.
Fuel and Purchased Power Expenses
Second Quarter 2017
vs.
Second Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
Third Quarter 2017
vs.
Third Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$21
 25.9 $23
 14.6$8
 7.1 $33
 12.3
Purchased power – non-affiliates1
 100.0 2
 200.01
 33.3 3
 75.0
Purchased power – affiliates
  2
 22.2(3) (60.0) (1) (7.1)
Total fuel and purchased power expenses$22
 $27
 $6
 $35
 
In the secondthird quarter 2017, total fuel and purchased power expenses were $108$126 million compared to $86$120 million for the corresponding period in 2016. The increase was due to a $17 million increase in natural gas prices and a $5$6 million increase in the volume of KWHs generated and purchased.
For year-to-date 2017, total fuel and purchased power expenses were $194$321 million compared to $167$286 million for the corresponding period in 2016. The increase was primarily due to a $34$42 million increase in the average cost of natural gas prices,and purchased power, partially offset by a $7$4 million decrease in coal prices and a $3 million decrease in the volume of KWHs generated and purchased.

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

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Details of Mississippi Power's generation and purchased power were as follows:
Second Quarter 2017 Second Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
Total generation (in millions of KWHs)
3,927 3,728 7,088 7,3154,453 4,255 11,542 11,570
Total purchased power (in millions of KWHs)(*)
121 188 362 449164 288 527 877
Sources of generation (percent)
      
Coal7 5 8 88 10 8 9
Gas93 95 92 9292 90 92 91
Cost of fuel, generated (in cents per net KWH)
  
Coal3.61 5.49 3.46 4.163.80 4.02 3.60 4.09
Gas2.73 2.17 2.69 2.162.77 2.64 2.72 2.34
Average cost of fuel, generated (in cents per net KWH)
2.79 2.33 2.76 2.322.86 2.79 2.80 2.50
Average cost of purchased power (in cents per net KWH)(*)
4.74 2.55 3.80 2.333.74 2.59 3.78 2.04
(*)Includes energy produced during the test period for the Kemper IGCC, which is accounted for in accordance with FERC guidance.
Fuel
In the secondthird quarter 2017, total fuel expense was $102$120 million compared to $81$112 million for the corresponding period in 2016. The increase was due to a 20%2.5% increase in the average cost of fuel per KWH generated, primarily due to a 26%4.5% higher cost of natural gas, and a 6%5.4% increase in the volume of KWHs generated.
For year-to-date 2017, total fuel expense was $180$301 million compared to $157$268 million for the corresponding period in 2016. The increase was due to a 19%12.0% increase in the average cost of fuel per KWH generated primarily due to a 25%16.2% higher cost of natural gas, partially offset by a 3% decrease in the volume of KWHs generated.gas.
Purchased Power
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$2 2.9 $8 5.9
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)
In the third quarter 2017, other operations and maintenance expenses were $66 million compared to $74 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.
For year-to-date 2017, other operations and maintenance expenses were $144$206 million compared to $136$211 million for the corresponding period in 2016. The increasedecrease was 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.

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See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined CycleRate Recovery of Kemper IGCC Costs2015 Rate Case" herein for additional information.

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Depreciation and Amortization
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(4) (8.9) $(3) (3.6)
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
In the secondthird quarter 2017, depreciation and amortization was $41$39 million compared to $45 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $81 million compared to $84$30 million for the corresponding period in 2016. The decreases wereincrease was primarily related to changes$6 million in amortization and deferrals associated with regulatory assets.assets and liabilities and $3 million in depreciation related to additional plant in service.
For year-to-date 2017, depreciation and amortization was $120 million compared to $114 million for the corresponding period in 2016. The increase was primarily related to $5 million in depreciation related to additional plant in service.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K.
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)
In the third quarter 2017, taxes other than income taxes were $25 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $77 million compared to $81 million for the corresponding period in 2016. These decreases were primarily due to a decrease in franchise taxes of $5 million 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.
Estimated Loss on Kemper IGCC
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$2,931 N/M $2,986 N/M
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
Prior to the project suspension on June 28, 2017, estimatedEstimated probable losses on the Kemper IGCC totaled $196of $34 million and $305 million$3.2 billion were recorded in the secondthird quarter and year-to-date 2017, respectively, compared to $81$88 million and $134$222 million in the secondthird quarter and year-to-date 2016, respectively. These losses reflected revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC prior to project suspension 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.
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 Order,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,probable. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded an$34 million and $2.9 billion of additional chargecharges to income in Junethe third quarter and year-to-date 2017, of $2.8 billion, which includesrespectively, 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 the Initial DOE Grants and excluding the Cost Cap Exceptions.

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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
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$6 20.0 $12 20.3
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 secondthird quarter 2017, AFUDC equity was $36$1 million compared to $30$31 million for the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $71$72 million compared to $59$90 million for the corresponding period in 2016. The increasesdecreases resulted from a higher AFUDC rate and an increase inthe Kemper IGCC CWIP subject to AFUDC prior to project suspension.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

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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
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$2 13.3 $6 19.4
Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(28) N/M $(23) 50.0
N/M - Not meaningful
In the secondthird quarter 2017, interest expense, net of amounts capitalized was $17$(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 $37$23 million compared to $31$46 million for the corresponding period in 2016. The increases weredecrease 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 in-service assets.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" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Income Taxes (Benefit)
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(864) N/M $(881) N/M
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
N/M - Not meaningful
In the secondthird quarter 2017, income tax benefit was $881taxes were $24 million compared to $17an income tax benefit of $2 million for the corresponding period in 2016. For year-to-date 2017, income tax benefit was $908$885 million compared to $27$29 million

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for the corresponding period in 2016. The changes were primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of 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 its 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. 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 economic growth. Thethe pace of economic growth and electricity demandthat 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

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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.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through 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, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi

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Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Mississippi 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 June 6,September 18, 2017, the EPA proposedpublished 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 matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information.
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.

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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)

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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 Note (B) to the Condensed Financial Statements under "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 JuneSeptember 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $7$3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at JuneSeptember 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.
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 proceeding itrelated 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, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Mississippi 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 Mississippi 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 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 services 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.

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The SSA provides Cooperative Energy the option to decrease its use of Mississippi Power's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in Mississippi Power's revenues is not expected to be significant through 2020.
In 2008, 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 result 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.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
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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. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersMississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Renewables
Mississippi Power placed in service twothree solar projects in January, 2017June, and June 2017. A third solar project is expected to be placed in service in the third quarterOctober 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 June 9,August 17, 2017, Mississippi Power submitted a CPCN to the Mississippi PSC approved Mississippi Power's CPCN for the approval of construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which if approved, 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 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.
On November 15, 2017, Mississippi Power is expected to make its annual 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 this matterthese 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 million effective with the first billing cycle for August 2017.

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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 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
At JuneSeptember 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $14$2 million compared to $37 million at December 31, 2016.
On November 15, 2017, Mississippi Power is expected 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 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.
Provision for Property Damage
On October 8, 2017, Hurricane Nate hit the Gulf Coast of Mississippi causing minor damage to 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.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
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

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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 remainder of the plant includes the gasifiers and the gas clean-up facilities.
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

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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. Most recently, inIn 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.

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Mississippi Power's Kemper IGCC 2010 project estimate cost estimate attotaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension (which includesin June 2017, the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs2013 MPSC Rate Order"), and actual costs incurred as of June 30, 2017, all of which include 100% of the coststotal cost estimate for the Kemper IGCC are as follows: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.
Cost Category
2010 Project Estimate(a)
 
Cost Estimate
at
Suspension(b)
 
June 30, 2017
Actual Costs
 (in billions)
Plant Subject to Cost Cap(c)(e)
$2.40
 $5.95
 $5.68
Lignite Mine and Equipment0.21
 0.23
 0.23
CO2 Pipeline Facilities
0.14
 0.11
 0.11
AFUDC(d)
0.17
 0.85
 0.85
Combined Cycle and Related Assets Placed in
Service – Incremental
(e)

 0.05
 0.05
General Exceptions0.05
 0.10
 0.08
Deferred Costs(e)

 0.23
 0.23
Additional DOE Grants
 (0.14) (0.14)
Total Kemper IGCC$2.97
 $7.38
 $7.09
(a)
Represents the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.
(b)Represents actual costs through June 30, 2017 and projected costs at the time of project suspension, including estimated post-in-service costs which were expected to be subject to the cost cap.
(c)
The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Cost Estimate at Suspension and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs2013 MPSC Rate Order" herein for additional information.
(d)
Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs2013 MPSC Rate Order." The Cost Estimate at Suspension also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
(e)Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are included in current rates and are being recognized through income; however, such costs remained in the Cost Estimate at Suspension and are reflected in the Actual Costs at June 30, 2017. The equity return associated with assets placed in service and other non-CWIP accounts deferred for regulatory purposes, as well as the wholesale portion of debt carrying costs, whether deferred or recognized through income, was not included in the Cost Estimate at Suspension or in the Actual Costs at June 30, 2017. At June 30, 2017, such deferred amounts totaled $33 million and $1 million, respectively.
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 Order,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. 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.

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ultimately canceled, additional pre-tax 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 $3.0 billion for the second quarter 2017 and $3.1 billion for the six months ended June 30, 2017.
As of June 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, of which $1.2 billion is included in plant in service, $14 million in materials and supplies, $22 million in other regulatory assets, current, and $95 million in other regulatory assets, deferred.
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. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
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 June 30, 2017, approximately $3.3 billion in actualthe time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was relatedsubject to the combined cycleconstruction cost cap, and associated facilitieswas net of the $137 million in Additional DOE Grants.
Mississippi Power reached and $2.8 billion was related tofiled a settlement agreement on August 21, 2017 with certain parties (not including the gasification portionsMPUS), which it believes met the conditions of the Kemper IGCC.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 Order,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.

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As of JuneSeptember 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

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$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 SMEPA.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 iswas 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 iswas 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 August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the

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transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal.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

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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 SMEPACooperative 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. With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
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 JuneSeptember 30, 2017, the balance associated with these regulatory assets was $117$113 million, of which $22$21 million is included in current assets. See "FERC Matters""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, withfor the first occurring as of May 31, 2016.2016 and 2017 calculations. At JuneSeptember 30, 2017, Mississippi Power's related regulatory liability included in its balance sheet 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).

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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 $493$494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $459$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.

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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 to 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. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (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 in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
In 2010 and as amended in 2012, Mississippi Power and SMEPACooperative Energy (formerly known as SMEPA) entered into an agreement whereby SMEPACooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC (15% Undivided Interest).IGCC. On May 20, 2015, SMEPACooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from SMEPACooperative Energy that were required to be returned to SMEPACooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA.Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in 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, 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

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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 Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Court.of an appeal.

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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, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have 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, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.
Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
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 by the Mississippi PSC and prohibits the cancellation of 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.
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
Approximately $370 million of positive cash flows is expected to result fromAll projected tax benefits previously received for bonus depreciation for the 2017 tax year, but may not all be realized in 2017 duerelated to net operating loss projections for the 2017 tax year, and is dependent upon placing the remainder of the Kemper IGCC were repaid in service by December 31, 2017.connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment any amount previously estimated as bonus depreciationfor income tax purposes, the related deduction would be claimed as a deduction under IRC Section 165. Asin the year of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment.abandonment. See Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined

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Cycle" 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 research and experimental (R&E)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, subject to approval ofwhich was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. Due toAs a result of the uncertainty related to this tax position,JCT approval, Mississippi Power hadrecognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. 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, and would result in a reversal of the related unrecognized tax benefits, excludingaccrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" and "Section"Section 174 Research and Experimental Deduction," respectively, herein for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome

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Other Matters
Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as 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.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstMississippi Power or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of

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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.
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, 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

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project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the JuneSeptember 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 Order,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 JuneSeptember 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 SMEPA.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 $5.96$6.00 billion ($3.943.96 billion after tax) through JuneSeptember 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $3.0 billion$34 million ($2.1 billion21 million after tax) and $81$88 million ($5054 million after tax) in the secondthird quarter 2017 and the secondthird quarter 2016, respectively, and total pre-tax charges of $3.1$3.2 billion ($2.2 billion after tax) and $134$222 million ($83137 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 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" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.

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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.
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. The new standard also requires enhanced disclosures 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, including

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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, 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(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 income statement outside 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. 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. Mississippi Power is currently evaluating the new standard. 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 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Mississippi Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Mississippi Power's financial statements.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the sixnine months ended JuneSeptember 30, 2017 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2022. Projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, and to expand and improve transmission and distribution facilities.
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 prepay $901 million of outstanding debt.
As of JuneSeptember 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $930$769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $107$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 $135$361 million for the first sixnine months of 2017, a decrease of $2$12 million as compared to the corresponding period in 2016. The decrease in cash provided from operating activities is primarily due to lowerdeferred income taxes related to the Kemper IGCC, the timing of payments for ad valorem taxes and materials and supplies, andpartially offset by the timing of payments received from affiliates and customers partially offset byand the completion of Mirror CWIP refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined CycleRate Recovery of Kemper IGCC Costs" and "Unrecognized Tax BenefitsSection 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $361$483 million for the first sixnine months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $142$129 million for the first sixnine months of 2017 primarily due to capital contributions from Southern Company, partially offset by redemptions of long-term debt.debt and short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first sixnine months of 2017 include an increase 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 reclassification of $1.2 billion in unsecured term loans to securities due within one year. Other significant changes include decreases of $2.5 billion in construction work in progress, $1.1 billion in total common stockholder's equity, $352CWIP, $756 million in accumulated deferred income taxes, and $300$299 million in deferred charges related to income taxes. All of these changes primarily resultresulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to tax refunds associated with the IRS Section 174 R&E settlement. See FUTURE EARNINGS POTENTIAL – "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" and NoteNotes (B) and (G) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative

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scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $935 million will be required through JuneSeptember 30, 2018 to fund maturities of long-term debt and $17$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 and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. See "Sources of Capital" and FUTURE EARNINGS POTENTIAL – "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $561$582 million for 2017, $192$203 million for 2018, $182$177 million for 2019, $235$204 million for 2020, $199 million for 2021, and $245$240 million for 2022. These estimated expenditures do not include potential compliance costs that may arise from 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.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.
Sources of Capital
Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, 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. 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 JuneSeptember 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $930$769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $107$94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as

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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 and 6 to the financial statements of Mississippi Power under "Recently Issued

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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""Going Concern" herein.
At JuneSeptember 30, 2017, Mississippi Power had approximately $140$231 million of cash and cash equivalents. Committed credit arrangements with banks at JuneSeptember 30, 2017 were as follows:
ExpiresExpires   
Executable Term
Loans
 
Expires Within One
Year
Expires   
Executable Term
Loans
 
Expires Within One
Year
20172017 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
2017 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)
$113
 $113
 $100
 $
 $13
 $13
 $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) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements, as well as Mississippi Power's term loan 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 JuneSeptember 30, 2017, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of JuneSeptember 30, 2017 was approximately $40 million. In addition, at JuneSeptember 30, 2017, Mississippi Power had approximately $50 million of fixed rate pollution control 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
June 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 $17
 2.9% $29
 3.1% $36
  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
(*)Average and maximum amounts are based upon daily balances during the three-month period ended JuneSeptember 30, 2017.

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Credit Rating Risk
At JuneSeptember 30, 2017, 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, Mississippi Power executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets 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

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sales, fuel transportation and storage, energy price risk management, and transmission. At JuneSeptember 30, 2017, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $243$255 million.
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or 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 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, Moody's revised its rating outlook for Mississippi Power from under review to stable.
Financing Activities
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, 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.

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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.


SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Wholesale revenues, non-affiliates$436
 $264
 $783
 $480
$510
 $387
 $1,293
 $866
Wholesale revenues, affiliates90
 107
 190
 204
105
 110
 295
 313
Other revenues3
 2
 6
 4
3
 3
 9
 10
Total operating revenues529
 373
 979
 688
618
 500
 1,597
 1,189
Operating Expenses:              
Fuel139
 96
 271
 187
189
 154
 460
 341
Purchased power, non-affiliates29
 21
 54
 35
36
 25
 90
 60
Purchased power, affiliates11
 2
 16
 8
7
 8
 23
 16
Other operations and maintenance97
 86
 190
 162
83
 81
 272
 246
Depreciation and amortization129
 81
 247
 154
131
 93
 379
 247
Taxes other than income taxes12
 6
 24
 13
13
 5
 37
 17
Total operating expenses417

292
 802
 559
459

366
 1,261
 927
Operating Income112
 81
 177
 129
159
 134
 336
 262
Other Income and (Expense):              
Interest expense, net of amounts capitalized(48) (22) (97) (43)(47) (35) (144) (78)
Other income (expense), net2
 1
 (2) 1
3
 2
 3
 3
Total other income and (expense)(46) (21) (99) (42)(44) (33) (141) (75)
Earnings Before Income Taxes66
 60
 78
 87
115
 101
 195
 187
Income taxes (benefit)(38) (41) (90) (65)(39) (102) (129) (167)
Net Income104
 101
 168
 152
154
 203
 324
 354
Less: Net income attributable to noncontrolling interests22
 12
 17
 13
30
 27
 48
 39
Net Income Attributable to Southern Power$82
 $89
 $151
 $139
$124
 $176
 $276
 $315
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months Ended June 30, For the Six Months Ended June 30,For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Net Income$104
 $101
 $168
 $152
$154
 $203
 $324
 $354
Other comprehensive income (loss):              
Qualifying hedges:              
Changes in fair value, net of tax of
$24, $(15), $20, and $(15), respectively
40
 (24) 32
 (24)
Reclassification adjustment for amounts included in net income,
net of tax of $(27), $8, $(30), and $8, respectively
(45) 13
 (48) 14
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
Total other comprehensive income (loss)(5) (11) (16) (10)5
 22
 (10) 12
Comprehensive Income99
 90
 152
 142
159
 225
 314
 366
Less: Comprehensive income attributable to noncontrolling interests22
 12
 17
 13
30
 27
 48
 39
Comprehensive Income Attributable to Southern Power$77
 $78
 $135
 $129
$129
 $198
 $266
 $327
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Six Months Ended June 30,For the Nine Months Ended September 30,
2017 20162017 2016
(in millions)(in millions)
Operating Activities:      
Net income$168
 $152
$324
 $354
Adjustments to reconcile net income to net cash provided from operating activities —      
Depreciation and amortization, total264
 159
404
 262
Deferred income taxes91
 (71)240
 (668)
Amortization of investment tax credits(28) (15)(42) (25)
Deferred revenues(34) (31)
Collateral deposits(1) (80)
Income taxes receivable, non-current(58) 
(42) 
Other, net(1) 9
(2) 19
Changes in certain current assets and liabilities —      
-Receivables(58) (76)(77) (82)
-Prepaid income taxes33
 (147)
-Other current assets20
 5
38
 (15)
-Accounts payable(45) 4
(31) 7
-Accrued taxes4
 62
79
 483
-Other current liabilities(8) 
5
 14
Net cash provided from operating activities348
 51
895
 269
Investing Activities:      
Business acquisitions(1,020) (502)(1,032) (1,134)
Property additions(145) (1,281)(218) (1,702)
Change in construction payables(167) (137)(166) (69)
Payments pursuant to LTSAs(68) (43)(99) (58)
Investment in restricted cash(16) (646)(16) (750)
Distribution of restricted cash27
 649
33
 746
Other investing activities(2) (25)7
 (41)
Net cash used for investing activities(1,391) (1,985)(1,491) (3,008)
Financing Activities:      
Increase in notes payable, net189
 695
Increase (decrease) in notes payable, net(89) 692
Proceeds —      
Senior notes
 1,241

 1,531
Capital contributions from parent company
 300

 800
Other long-term debt43
 63
Redemptions — Other long-term debt(4) (84)
Distributions to noncontrolling interests(40) (11)(89) (22)
Capital contributions from noncontrolling interests73
 179
79
 367
Purchase of membership interests from noncontrolling interests
 (129)
 (129)
Payment of common stock dividends(158) (136)(238) (204)
Other financing activities(21) (13)(27) (14)
Net cash provided from financing activities43
 2,126
Net cash provided from (used for) financing activities(325) 3,000
Net Change in Cash and Cash Equivalents(1,000) 192
(921) 261
Cash and Cash Equivalents at Beginning of Period1,099
 830
1,099
 830
Cash and Cash Equivalents at End of Period$99
 $1,022
$178
 $1,091
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —      
Interest (net of $4 and $21 capitalized for 2017 and 2016, respectively)$113
 $42
Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively)$144
 $49
Income taxes, net(117) 115
(343) 71
Noncash transactions — Accrued property additions at end of period19
 108
16
 210
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $99
 $1,099
 $178
 $1,099
Receivables —        
Customer accounts receivable 158
 102
 148
 102
Other accounts receivable 37
 34
Other 61
 34
Affiliated 65
 57
 74
 57
Fossil fuel stock 15
 15
 15
 15
Materials and supplies 349
 337
 351
 337
Prepaid income taxes 41
 74
 51
 74
Other current assets 26
 39
 26
 39
Total current assets 790
 1,757
 904
 1,757
Property, Plant, and Equipment:        
In service 13,731
 12,728
 13,734
 12,728
Less: Accumulated provision for depreciation 1,689
 1,484
 1,823
 1,484
Plant in service, net of depreciation 12,042
 11,244
 11,911
 11,244
Construction work in progress 344
 398
 425
 398
Total property, plant, and equipment 12,386
 11,642
 12,336
 11,642
Other Property and Investments:        
Intangible assets, net of amortization of $35 and $22
at June 30, 2017 and December 31, 2016, respectively
 423
 436
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 423
 436
 417
 436
Deferred Charges and Other Assets:        
Prepaid LTSAs 61
 101
 77
 101
Accumulated deferred income taxes 536
 594
 400
 594
Income taxes receivable, non-current 69
 11
 53
 11
Other deferred charges and assets — affiliated 28
 13
 6
 13
Other deferred charges and assets — non-affiliated 410
 615
 455
 615
Total deferred charges and other assets 1,104
 1,334
 991
 1,334
Total Assets $14,703
 $15,169
 $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 June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $909
 $560
 $864
 $560
Notes payable 398
 209
 120
 209
Accounts payable —        
Affiliated 68
 88
 93
 88
Other 93
 278
 84
 278
Accrued taxes —        
Accrued income taxes 35
 148
 101
 148
Other accrued taxes 21
 7
 30
 7
Accrued interest 25
 36
 36
 36
Acquisitions payable 
 461
 
 461
Contingent consideration 11
 46
 15
 46
Other current liabilities 67
 70
 58
 70
Total current liabilities 1,627
 1,903
 1,401
 1,903
Long-term Debt 4,816
 5,068
 4,946
 5,068
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 174
 152
 191
 152
Accumulated deferred ITCs 1,914
 1,839
 1,900
 1,839
Asset retirement obligations 69
 64
 76
 64
Other deferred credits and liabilities 238
 304
 232
 304
Total deferred credits and other liabilities 2,395
 2,359
 2,399
 2,359
Total Liabilities 8,838
 9,330
 8,746
 9,330
Redeemable Noncontrolling Interests 51
 164
 59
 164
Common Stockholder's Equity:        
Common stock, par value $.01 per share —        
Authorized — 1,000,000 shares        
Outstanding — 1,000 shares 
 
 
 
Paid-in capital 3,671
 3,671
 3,661
 3,671
Retained earnings 717
 724
 762
 724
Accumulated other comprehensive income 19
 35
 25
 35
Total common stockholder's equity 4,407
 4,430
 4,448
 4,430
Noncontrolling interests 1,407
 1,245
 1,395
 1,245
Total stockholders' equity 5,814
 5,675
 5,843
 5,675
Total Liabilities and Stockholders' Equity $14,703
 $15,169
 $14,648
 $15,169
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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SECONDTHIRD QUARTER 2017 vs. SECONDTHIRD QUARTER 2016
AND
YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016


OVERVIEW
Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction and development of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities.entities, as well as commercial and industrial customers. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the sixnine months ended JuneSeptember 30, 2017, Southern Power acquired or completed the construction of, and placed in service, approximately 498 MWs of solar and wind facilities. In addition, Southern Power began construction at the recently acquired Cactus Flats wind facility, continued developingdevelopment of its portfolio of wind projects, as well as the construction to expandand continued expansion of the Mankato natural gas facility by 345 MWs of capacity. Subsequent to June 30, 2017, Southern Power acquired and commenced construction of Cactus Flats, a 148-MW wind 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 JuneSeptember 30, 2017, Southern Power had an average investment coverage ratio of 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years. These ratios include the PPAs and capacity associated with facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL "Power Sales Agreements" herein for additional information.
Southern Power continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$(7) (7.9) $12 8.6
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 secondthird quarter 2017 was $82$124 million compared to $89$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 from debt issuancesprimarily due to fund acquisitionsa decrease in capitalized interest associated with completing construction of and construction and an increaseplacing in net income attributable to noncontrolling interests, significantlyservice 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 $151$276 million compared to $139$315 million for the corresponding period in 2016. The increasedecrease was primarily due to additional operating income from new generating facilities, as well as increased federaldecreased income tax benefits resulting from a reduction in solar ITCs, partially offset by an increase in wind PTCs, partially offset byand increased interest expense from debt issuances to fund acquisitionsSouthern Power's growth strategy and construction. 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"Acquisitions" and

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" and "Construction Projects"Projects" of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.

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Operating Revenues
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$156 41.8 $291 42.3
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
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 wind 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 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 electricityenergy 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 for electricityrelated 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, and other factors.
See FUTURE EARNINGS POTENTIAL – "Power"Power Sales Agreements"Agreements" herein for additional information regarding Southern Power's PPAs.
Details of Southern Power's operating revenues were as follows:
Second Quarter 2017 Second Quarter 2016 Year-to-Date 2017 Year-to-Date 2016Third Quarter 2017 Third Quarter 2016 Year-to-Date 2017 Year-to-Date 2016
(in millions)(in millions)
PPA capacity revenues$149
 $133
 $298
 $258
$169
 $149
 $466
 $406
PPA energy revenues270
 168
 466
 285
299
 247
 765
 532
Total PPA revenues419
 301
 764
 543
468
 396
 1,231
 938
Non-PPA revenues107
 70
 209
 141
147
 101
 357
 241
Other revenues3
 2
 6
 4
3
 3
 9
 10
Total operating revenues$529
 $373
 $979
 $688
$618
 $500
 $1,597
 $1,189

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In the secondthird quarter 2017, total operating revenues were $529$618 million, reflecting a $156$118 million, or 42%24%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $16$20 million, or 12%13%, primarily due to additional customer capacity requirements and a new PPAsPPA related to natural gas facilities and additional customer load requirements.facilities.
PPA energy revenues increased $102$52 million, or 61%21%, primarily due to an $85a $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 $20$21 million increase in sales from new natural gas PPAs and additional customer load requirements.the average cost of fuel.
Non-PPA revenues increased $37$46 million, or 53%46%, due to a $23$58 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well asoffset by a $14$12 million increasedecrease in the price of energy primarily due to increased natural gas prices.in the wholesale markets.
For year-to-date 2017, total operating revenues were $979 million,$1.6 billion, reflecting a $291$408 million, or 42%34%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $40$60 million, or 16%15%, primarily due to additional customer capacity requirements and a new PPAsPPA related to natural gas facilities and additional customer load requirements.facilities.
PPA energy revenues increased $181$233 million, or 64%44%, primarily due to a $137$188 million increase in sales from new solar and wind facilities and a $37$35 million increase in sales from new 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 additionalreduced customer load requirements.load.
Non-PPA revenues increased $68$116 million, or 48%, due to a $48$104 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $20$12 million increase in the price of energy primarily due to increased natural gas prices.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. Details of Southern Power's generation and purchased power were as follows:
Second Quarter 2017Second Quarter 2016 Year-to-Date 2017Year-to-Date 2016Third Quarter 2017Third Quarter 2016 Year-to-Date 2017Year-to-Date 2016
(in billions of KWHs)(in billions of KWHs)
Generation10.99.1 20.616.712.511.1 33.227.9
Purchased power1.20.9 2.21.51.20.9 3.42.5
Total generation and purchased power12.110.0 22.818.213.712.0 36.630.4
  
Total generation and purchased power, excluding solar, wind, and tolling agreements5.65.7 10.511.07.26.7 17.817.7
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power.

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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

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Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
Second Quarter 2017
vs.
Second Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
Third Quarter 2017
vs.
Third Quarter 2016
 Year-to-Date 2017
vs.
Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change) (change in millions) (% change)
Fuel$43
 44.8 $84
 44.9$35
 22.7 $119
 34.9
Purchased power17
 73.9 27
 62.810
 30.3 37
 48.7
Total fuel and purchased power expenses$60
 $111
 $45
 $156
 
In the secondthird quarter 2017, total fuel and purchased power expenses increased $60$45 million, or 50.4%24.1%, compared to the corresponding period in 2016. Fuel expense increased $43$35 million primarily due to a $51$29 million increase in the average cost of natural gas per KWH generated and an $8 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $10 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 increase in the average cost of natural gas per KWH generated, partially offset by an $8a $19 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $17$37 million primarily due to a $10$28 million increase in the volume of KWHs purchased and a $6 million increase associated with the average cost of purchased power.
For year-to-date 2017, total fuel and purchased power expenses increased $111 million, or 48.3%, compared to the corresponding period in 2016. Fuel expense increased $84 million primarily due to a $105 million increase in the average cost of natural gas per KWH generated, partially offset by a $22 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $27 million due to a $19 million increase in the volume of KWHs purchased and an $8$9 million increase associated with the average cost of purchased power.
Other Operations and Maintenance Expenses
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$11 12.8 $28 17.3
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 secondthird quarter 2017, other operations and maintenance expenses were $97$83 million compared to $86$81 million for the corresponding period in 2016. The increase was primarily due to a $19$13 million increase associated with new solar, wind, and gas facilities, and a $5 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $9$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 $190$272 million compared to $162$246 million for the corresponding period in 2016. The increase was primarily due to a $35$48 million increase associated with new solar, wind, and gas facilities and a $10an $8 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $16$22 million decrease in scheduled outage maintenance expenses and a $4an $8 million decrease in non-outage operations and maintenance expenses.
Depreciation and Amortization
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$48 59.3 $93 60.4
In the second quarter 2017, depreciation and amortization was $129 million compared to $81 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $247 million compared to

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$154Depreciation 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)
$38 40.9 $132 53.4
In the third quarter 2017, depreciation and amortization was $131 million compared to $93 million for the corresponding period 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 $13 million compared to $5 million 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
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$26 118.2 $54 125.6
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 secondthird quarter 2017, interest expense, net of amounts capitalized was $48$47 million compared to $22$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 $16$39 million in interest expense relateddue to additionalan increase in average outstanding long-term debt, issued in 2016, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $9 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
For year-to-date 2017, interest expense, net of amounts capitalized was $97 million compared to $43 million for the corresponding period in 2016. The increase was primarily due to an increase of $36 million in interest expense related to additional debt issued in 2016, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $17$25 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
Other Income (Expense), Net
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
Third Quarter 2017 vs. Third Quarter 2016Third Quarter 2017 vs. Third Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change) (% change) (change in millions) (% change)
$1 100.0 $(3) (300.0) 50.0 $— 
In the secondthird quarter 2017, other income (expense), net was $2$3 million compared to $1$2 million for the corresponding period in 2016. For year-to-date 2017, otherOther income (expense), net was $(2) million compared to $1$3 million for the corresponding period inboth year-to-date 2017 and 2016. The changes include increases of $99$36 million and $116$152 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the secondthird quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings. See Note (H) to the Condensed Financial Statements herein for additional information.

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Income Taxes (Benefit)
Second Quarter 2017 vs. Second Quarter 2016 Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions) (% change) (change in millions) (% change)
$3 7.3 $(25) (38.5)
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
In the secondthird quarter 2017, income tax benefit was $38$39 million compared to $41$102 million for the corresponding period in 2016. The decrease was primarily due to a $29$61 million decrease in ITCincome tax benefits partially offset by a $27 million increase in wind PTC benefits.from solar ITCs.
For year-to-date 2017, income tax benefit was $90$129 million compared to $65$167 million for the corresponding period in 2016. The increasedecrease was primarily due to a $57$102 million decrease in income tax benefits from solar ITCs, partially offset by a $58 million increase in wind PTC benefits,PTCs and a $4 million increase resulting from state apportionment rate changes, and a $4 million increase related to lower pre-tax earnings, partially offset by a $41 million decrease in ITC benefits.changes.
See Note (G) to the Condensed Financial Statements 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.ITCs and PTCs.

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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; 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.
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.
Demand for electricity is primarily driven by economic growth. Thethe pace of economic growth and electricity demandthat 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, cost of generation from facilities 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 JuneSeptember 30, 2017, Southern Power's average investment coverage ratio for its generating assets, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount, was 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years.

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Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule.

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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 June 6,September 18, 2017, the EPA proposedpublished 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 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 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 proceeding itrelated 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 accordance with the February 2, 2017

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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 sixnine months ended JuneSeptember 30, 2017, in accordance with Southern Power's overall growth strategy, Southern Renewable Partnerships, LLC (SRP), one of Southern Power's wholly-owned subsidiaries acquired the Bethel wind facility.project discussed below. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein 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
The aggregate amounts of revenue and net income excluding impacts from PTCs, recognized by Southern Power related to the Bethel facility included in theSouthern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel 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 JuneSeptember 30, 2017, Southern Power acquired a 100% ownership interest in and commenced constructionpurchased all of the Cactus Flats 148-MW wind facility,redeemable noncontrolling interests, representing 10% of the majoritymembership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of which is covered by two PPAs, which expire in 2030 and

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2033. The facility is expectednotes payable to be placed in service in mid-2018. The ultimate outcome of this matter cannot be determined at this time.Turner Renewable Energy, LLC.
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
During the sixnine months ended JuneSeptember 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through JuneSeptember 30, 2017, total costs of construction incurred for these projects were $421$494 million, of which $49$122 million remained in CWIP for the Mankato facility acquired in 2016.CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be $170between $360 million to $190and $415 million for the Mankato facility.and Cactus Flats facilities. The ultimate outcome of this matterthese matters cannot be determined at this time.

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Project FacilityResource
Approximate Nameplate Capacity (MW)
LocationActual/Expected CODPPA CounterpartiesPPA Contract Period
Projects Completed During the SixNine Months Ended JuneSeptember 30, 2017
East PecosSolar120Pecos County, TXMarch 2017Austin Energy15 years
LamesaSolar102Dawson County, TXApril 2017City of Garland, Texas15 years
       
ProjectProjects Under Construction as of JuneSeptember 30, 2017
Cactus Flats(*)
Wind148Concho County, TXThird quarter 2018General Motors, LLC
and
General Mills Operations, LLC
12 years
and
15 years
MankatoNatural Gas345Mankato, MNSecond quarter 2019Northern States Power Company20 years
(*)On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.
Development Projects
In December 2016, as part of Southern Power's renewable development strategy, SRPone of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. 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 Note (G) to the Condensed Financial Statements herein for additional information.
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate 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 result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the

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U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthern Power or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatements

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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.
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.
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.
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. The new standard also requires enhanced disclosures 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

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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 and

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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, 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. Southern Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Power's financial statements.
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 JuneSeptember 30, 2017. 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 anticipates utilizing third-party tax equity as one of the financing sources to fund its renewable growth strategy; however, the use of third-party tax equity structures is not expected to have a material impact on future earnings. Subsequent to September 30, 2017, Southern Power secured third-party tax equity funding for the recently acquired Cactus Flats project subject to achieving commercial operation and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.
Net cash provided from operating activities totaled $348$895 million for the first sixnine months of 2017 compared to $51$269 million for the first sixnine months of 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales arising from new solar and wind facilities, and a decrease in income taxes paid, partially offset by an increase in interest paid. 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 $1.4$1.5 billion for the first sixnine months of 2017 primarily due to payments for renewable acquisitions and the construction of generating facilities. See FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided fromused for financing activities totaled $43$325 million for the first sixnine months of 2017 primarily due to common stock dividend payments, a decrease in notes payable, and contributions fromdistributions to noncontrolling interests, partially offset by dividends to Southern Company and distributions tocapital contributions from noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first sixnine months of 2017 include a $1.0 billion increase in property, plant,

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and equipment in-service primarily related to acquisitions and completing construction of and placing in service solar facilities, a $921 million decrease in cash and cash equivalents, and a $798 million increase in property, plant, and equipment in-service primarily related to acquisitions, as well as a $54$461 million decrease in CWIP primarily due to East Pecos and Lamesa being placed in service, partially offset by equipment purchased for wind construction projects. acquisitions payable.
See FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase

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commitments. Approximately $909$864 million will be required to repay maturities of long-term debt through JuneSeptember 30, 2018.
Southern Power's construction program includes estimates for potential plant acquisitions, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Actual capital costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, short-term debt, securities issuances, term loans, tax equity partnership contributions, 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 JuneSeptember 30, 2017, Southern Power's current liabilities exceeded current assets by $837$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. In 2017, Southern Power expects to utilize the debt capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.
As of June 30, 2017, Southern Power had cash and cash equivalents of approximately $99 million.
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, Southern Power had cash and cash equivalents of approximately $178 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 JuneSeptember 30, 2017.

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Details of commercial paper were as follows:
 
Short-term Debt at
June 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$398
1.5% $328
 1.3% $419
 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
(*)Average and maximum amounts are based upon daily balances during the three-month period ended JuneSeptember 30, 2017.
At JuneSeptember 30, 2017, Southern Power had a committed credit facility (Facility) of $750 million, of which $75$22 million has been used for letters of credit and $675$728 million remains unused. In May 2017, Southern Power amended the 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. 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

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needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
In December 2016, Southern Power entered into an agreement foralso has a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At JuneSeptember 30, 2017, the total amount available under this letter$111 million has been used for letters of credit facility was $62 million.and $9 million remains unused.
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, transmission, and foreign currency risk management.transmission.

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The maximum potential collateral requirements under these contracts at JuneSeptember 30, 2017 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and/or Baa2$38
$37
At BBB- and/or Baa3$392
$398
At BB+ and/or Ba1(*)
$1,127
$1,124
(*)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 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 revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Power) from stable to negative.
Financing Activities
In September 2017, Southern Power did not issue or redeem any securities duringamended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the six months ended June 30, 2017.

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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.

SOUTHERN COMPANY GAS
AND SUBSIDIARY COMPANIES

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
Successor  Predecessor Successor  PredecessorSuccessor  Predecessor
For the Three Months Ended June 30,  For the Three Months Ended June 30, For the Six Months Ended June 30,  For the Six Months Ended June 30,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  20162017 2016 2017 2016  2016
(in millions)  (in millions) (in millions)  (in millions)(in millions)  (in millions)
Operating Revenues:                   
Natural gas revenues (includes revenue taxes of
$19, $17, $67, and $57 for the periods presented,
respectively)
$684
  $539
 $2,214
  $1,841
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
Other revenues32
  32
 62
  64
33
 25
 95
 25
  64
Total operating revenues716
  571
 2,276
  1,905
565
 543
 2,841
 543
  1,905
Operating Expenses:                   
Cost of natural gas232
  184
 951
  755
134
 133
 1,085
 133
  755
Cost of other sales6
  7
 13
  14
7
 2
 20
 2
  14
Other operations and maintenance213
  213
 467
  454
205
 216
 671
 216
  454
Depreciation and amortization125
  104
 244
  206
125
 116
 370
 116
  206
Taxes other than income taxes44
  37
 114
  99
26
 29
 140
 29
  99
Merger-related expenses
  53
 
  56

 35
 
 35
  56
Total operating expenses620
  598
 1,789
  1,584
497
 531
 2,286
 531
  1,584
Operating Income (Loss)96
  (27) 487
  321
Operating Income68
 12
 555
 12
  321
Other Income and (Expense):                   
Earnings from equity method investments29
  1
 68
  2
32
 29
 100
 29
  2
Interest expense, net of amounts capitalized(48)  (48) (94)  (96)(51) (39) (145) (39)  (96)
Other income (expense), net3
  2
 7
  5
18
 9
 26
 9
  5
Total other income and (expense)(16)  (45) (19)  (89)(1) (1) (19) (1)  (89)
Earnings (Loss) Before Income Taxes80
  (72) 468
  232
Income taxes (benefit)31
  (24) 180
  87
Net Income (Loss)49
  (48) 288
  145
Earnings Before Income Taxes67
 11
 536
 11
  232
Income taxes52
 7
 233
 7
  87
Net Income15
 4
 303
 4
  145
Less: Net income attributable to noncontrolling interest
  3
 
  14

 
 
 
  14
Net Income (Loss) Attributable to Southern Company Gas$49
  $(51) $288
  $131
Net Income Attributable to
Southern Company Gas
$15
 $4
 $303
 $4
  $131
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 Successor  Predecessor
 For the Three Months Ended June 30,  For the Three Months Ended June 30, For the Six Months Ended June 30,  For the Six Months Ended June 30,
 2017  2016 2017  2016
 (in millions)  (in millions) (in millions)  (in millions)
Net Income (Loss)$49
  $(48) $288
  $145
Other comprehensive income (loss):         
Qualifying hedges:         
Changes in fair value, net of tax of
$(1), $(7), $(2), and $(23), respectively
(1)  (12) (2)  (41)
Reclassification adjustment for amounts included in
net income, net of tax of $-, $-, $-, and $-,
respectively

  2
 
  1
Pension and other postretirement benefit plans:         
Reclassification adjustment for amounts included in
net income, net of tax of $-, $2, $-, and $4,
respectively

  2
 (1)  5
Total other comprehensive income (loss)(1)  (8) (3)  (35)
Comprehensive Income (Loss)48
  (56) 285
  110
Less: Comprehensive income attributable to
noncontrolling interest

  3
 
  14
Comprehensive Income (Loss) Attributable to
Southern Company Gas
$48
  $(59) $285
  $96
 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  PredecessorSuccessor  Predecessor
For the Six Months Ended June 30,  For the Six Months Ended June 30,For the Nine Months Ended September 30, July 1, 2016 through September 30,  January 1, 2016 through
June 30,
2017  20162017 2016  2016
(in millions)  (in millions)(in millions)  (in millions)
Operating Activities:          
Net income$288
  $145
$303
 $4
  $145
Adjustments to reconcile net income to net cash provided from operating activities —          
Depreciation and amortization, total244
  206
370
 116
  206
Deferred income taxes144
  8
265
 (30)  8
Pension, postretirement, and other employee benefits(4) (123)  5
Stock based compensation expense19
  20
25
 11
  20
Hedge settlements
  (26)
 (35)  (26)
Mark-to-market adjustments(49)  162
(32) 17
  162
Other, net(53)  (77)(67) (47)  (82)
Changes in certain current assets and liabilities —          
-Receivables420
  181
534
 (18)  181
-Natural gas for sale, net of temporary LIFO liquidation223
  273

 (222)  273
-Prepaid income taxes24
  151
(7) 1
  151
-Other current assets(12)  37
(42) (36)  37
-Accounts payable(102)  43
(169) 78
  43
-Accrued taxes(8)  41
(24) (11)  41
-Accrued compensation(12)  (21)(11) (36)  (21)
-Other current liabilities25
  (30)8
 (11)  (30)
Net cash provided from operating activities1,151
  1,113
Net cash provided from (used for) operating activities1,149
 (342)  1,113
Investing Activities:          
Property additions(684)  (509)(1,093) (287)  (509)
Cost of removal, net of salvage(25)  (32)(45) (21)  (32)
Change in construction payables, net23
  (7)49
 9
  (7)
Investment in unconsolidated subsidiaries(111)  (14)(128) (1,421)  (14)
Returned investment in unconsolidated subsidiaries22
 2
  3
Other investing activities16
  3
3
 3
  
Net cash used for investing activities(781)  (559)(1,192) (1,715)  (559)
Financing Activities:          
Decrease in notes payable, net(631)  (896)
Increase (decrease) in notes payable, net(323) 472
  (896)
Proceeds —          
First mortgage bonds
  250
200
 
  250
Capital contributions from parent company57
  
79
 1,089
  
Senior notes450
  350
450
 900
  350
Redemptions and repurchases — First mortgage bonds
  (125)
Redemptions and repurchases —      
Medium-term notes(22) 
  
First mortgage bonds
 
  (125)
Senior notes
 (300)  
Distributions to noncontrolling interest
  (19)
 
  (19)
Payment of common stock dividends(221)  (128)(332) (63)  (128)
Other financing activities(6)  10
(7) (8)  10
Net cash used for financing activities(351)  (558)
Net cash provided from (used for) financing activities45
 2,090
  (558)
Net Change in Cash and Cash Equivalents19
  (4)2
 33
  (4)
Cash and Cash Equivalents at Beginning of Period19
  19
19
 15
  19
Cash and Cash Equivalents at End of Period$38
  $15
$21
 $48
  $15
Supplemental Cash Flow Information:          
Cash paid (received) during the period for —          
Interest (net of $7 and $3 capitalized for 2017 and 2016, respectively)$105
  $119
Interest (net of $9, $2, and $3 capitalized, respectively)$146
 $86
  $119
Income taxes, net20
  (100)17
 54
  (100)
Noncash transactions — Accrued property additions at end of period84
  41
112
 50
  41
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)
 
Assets At June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $38
 $19
 $21
 $19
Receivables —        
Energy marketing receivables 482
 623
 427
 623
Customer accounts receivable 270
 364
 221
 364
Unbilled revenues 69
 239
 61
 239
Other accounts and notes receivable 63
 76
 61
 76
Accumulated provision for uncollectible accounts (35) (27) (26) (27)
Materials and supplies 24
 26
 24
 26
Natural gas for sale 477
 631
 631
 631
Prepaid expenses 69
 80
 103
 80
Assets from risk management activities, net of collateral 114
 128
 103
 128
Other regulatory assets, current 72
 81
 96
 81
Other current assets 20
 10
 25
 10
Total current assets 1,663
 2,250
 1,747
 2,250
Property, Plant, and Equipment:        
In service 14,850
 14,508
 15,383
 14,508
Less: Accumulated depreciation 4,550
 4,439
 4,567
 4,439
Plant in service, net of depreciation 10,300
 10,069
 10,816
 10,069
Construction work in progress 779
 496
 596
 496
Total property, plant, and equipment 11,079
 10,565
 11,412
 10,565
Other Property and Investments:        
Goodwill 5,967
 5,967
 5,967
 5,967
Equity investments in unconsolidated subsidiaries 1,610
 1,541
 1,609
 1,541
Other intangible assets, net of amortization of $80 and $34
at June 30, 2017 and December 31, 2016, respectively
 320
 366
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
 21
 21
Total other property and investments 7,918
 7,895
 7,897
 7,895
Deferred Charges and Other Assets:        
Other regulatory assets, deferred 963
 973
 944
 973
Other deferred charges and assets 186
 170
 190
 170
Total deferred charges and other assets 1,149
 1,143
 1,134
 1,143
Total Assets $21,809
 $21,853
 $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 June 30, 2017 At December 31, 2016 At September 30, 2017 At December 31, 2016
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $22
 $22
 $
 $22
Notes payable 626
 1,257
 934
 1,257
Energy marketing trade payables 534
 597
 451
 597
Accounts payable 327
 348
 368
 348
Customer deposits 134
 153
 137
 153
Accrued taxes —        
Accrued income taxes 23
 26
 
 26
Other accrued taxes 63
 68
 70
 68
Accrued interest 50
 48
 66
 48
Accrued compensation 45
 58
 46
 58
Liabilities from risk management activities, net of collateral 20
 62
 28
 62
Other regulatory liabilities, current 146
 102
 126
 102
Accrued environmental remediation, current 63
 69
 54
 69
Temporary LIFO liquidation 69
 
Other current liabilities 113
 108
 112
 108
Total current liabilities 2,235
 2,918
 2,392
 2,918
Long-term Debt 5,677
 5,259
 5,862
 5,259
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 2,091
 1,975
 2,214
 1,975
Employee benefit obligations 432
 441
 431
 441
Other cost of removal obligations 1,638
 1,616
 1,656
 1,616
Accrued environmental remediation, deferred 353
 357
 345
 357
Other regulatory liabilities, deferred 50
 51
 35
 51
Other deferred credits and liabilities 91
 127
 88
 127
Total deferred credits and other liabilities 4,655
 4,567
 4,769
 4,567
Total Liabilities 12,567
 12,744
 13,023
 12,744
Common Stockholder's Equity:        
Common stock, par value $0.01 per share —        
Authorized — 100 million shares        
Outstanding — 100 shares 
 
 
 
Paid in capital 9,164
 9,095
 9,185
 9,095
Retained earnings (accumulated deficit) 55
 (12)
Accumulated deficit (41) (12)
Accumulated other comprehensive income 23
 26
 23
 26
Total common stockholder's equity 9,242
 9,109
 9,167
 9,109
Total Liabilities and Stockholder's Equity $21,809
 $21,853
 $22,190
 $21,853
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.



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


OVERVIEW
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. 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) to the Condensed Financial Statements herein and "BUSINESS – 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 constructive regulatory environments, to maintain and grow natural gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas 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 Southern Company Gas for the foreseeable future.
Merger, Acquisition, and AcquisitionDisposition Activities
On July 1, 2016, Southern Company Gas completed the Merger, which was accounted for by Southern Company using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for Southern Company Gas assets, liabilities, and equity as of 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 $24$28 million and $58$86 million from this investment in the secondsuccessor third quarter and year-to-date 2017, respectively.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.
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. for a total cash purchase price of $1.7 billion. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required 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.

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Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "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, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms, 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 all of the

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earnings upside in the event of colder-than-normal weather for gas distribution operations in Illinois and most of the earnings upside for gas marketing services.upside.
The number of customers at 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 and Illinois.
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.
Seasonality of Results
DuringHeating Season is the months ofperiod 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 during athroughout 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
Net income attributable to Southern Company Gas for the successor second quarter 2017 and net loss attributable to Southern Company Gas for the predecessor second quarter 2016 were $49 million and $51 million, respectively. Net income attributable to Southern Company Gas for the successor year-to-date 2017 and the predecessor year-to-date 2016 was $288 million and $131 million, respectively.
As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in the successor period. Net income for the successor second quarter 2017 was negatively impacted by $5 million due to the pushdown of acquisition accounting related to the Merger and included $10 million in after-tax earnings from the SNG investment, net of related interest expense. Also reflected in net income was an increase of $12 million, after tax, from additional infrastructure replacement programs at gas distribution operations, net of increased depreciation and a base rate increase at Atlanta Gas Light effective March 1, 2017. The successor second quarter 2017 also included $11 million in after-tax losses from commercial activity and $8 million in after-tax mark-to-market gains at wholesale gas services.
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)(% change)
$11N/M
Net loss attributable to Southern Company Gas for the predecessor second quarter 2016 included $39 million in after-tax Merger-related expenses, as well as $5 million in after-tax losses from commercial activity at wholesale gas services and $50 million in net after-tax mark-to-market losses at wholesale gas services and gas marketing services due to changes in natural gas price volatility in the period.N/M - Not meaningful
Net income attributable to Southern Company Gas was $15 million for the successor year-to-datethird quarter 2017 compared to $4 million for the corresponding period in 2016. This increase was negatively impacted by $2 millionprimarily due to the pushdown$11 million of acquisition accounting related to the Merger and included $25 million in after-tax earningsadditional income from the SNG investment, net of related interest expense. The successor year-to-date 2017 included an increase of $19 million, after tax, from additional infrastructure replacement programs at gas distribution operations,and base rate increases, net of increasedassociated depreciation, and a base rate increase at Atlanta Gas Light effective March 1, 2017. The successor year-to-date 2017 also included $41$7 million in after-tax gainsgain from commercial activitythe settlement of contractor litigation claims, partially offset by $12 million lower net income at wholesale gas services, $27services. Also contributing to the increase was $24 million in net after-tax mark-to-market gains at wholesale gas services and gas marketing services, and a reduction of $9 million, after tax, resulting from warmer-than-normal weather, net of hedging.
Net income attributable to Southern Company Gas for the predecessor year-to-date 2016 included $41 million in after-tax Merger-related expenses and $21in the third quarter 2016, partially offset by $23 million of additional deferred income tax expense in after-tax mark-to-market gains from commercial activity atthe third quarter 2017.

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  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 from wholesale gas services and $38 million in earnings from the SNG investment, net of related interest expense. Also included in net income for this period was $29 million generated from the continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017, less the associated increases in depreciation. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Base Rate Cases" herein. These increases were partially offset by $23 million 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 reflectedincluded 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 $38attributable to Southern Company Gas in the successor periods.
Natural Gas Revenues
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$14 2.7
In the third quarter 2017, natural gas revenues were $532 million compared to $518 million for the corresponding period in net after-tax mark-to-market2016.
Details of the changes in natural gas revenues were as follows:
  Third Quarter 2017
  (in millions) (% change)
Natural gas – prior year $518
  
Estimated change resulting from –    
Infrastructure replacement programs and base rate increases 25
 4.8 %
Gas costs and other cost recovery 1
 0.2
Mark-to-market adjustments at gas marketing services 3
 0.6
Wholesale gas services (16) (3.1)
Other 1
 0.2
Natural gas – current year $532
 2.7 %
The increase in natural gas revenue primarily relates to gas distribution operations 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 were partially offset by mark-to-

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market losses from derivative instruments at wholesale gas services and gas marketing services due to changes in natural gas prices and a decrease of $5 million, after tax, resulting from warmer-than-normal weather, net of hedging.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.
Natural Gas Revenues
Natural gas revenues for the successor second quarter 2017 and the predecessor second quarter 2016 were $684 million and $539 million, respectively. Natural gas revenues for
  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, and the predecessor year-to-date 2016 were $2.2 billion and $1.8 billion, respectively.
Naturalnatural gas revenues for the successor second quarter 2017 included recovery of $232 million$1.1 billion in cost of natural gas and $12$95 million in net lossesrevenues from wholesale gas services.services, net of $14 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues were $26$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, primarily at Atlanta Gas Light effective March 1, 2017, partially offset by a $2$16 million decrease attributable to warmer-than-normal weather, net of hedging.
NaturalFor 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 for the predecessor second quarter 2016 reflectedincluded recovery of $184$133 million and $755 million, respectively, in cost of natural gas, and $95as well as $8 million in net losses from wholesale gas services, primarily due to mark-to-market losses on storage, transportation, and forward commodity derivatives.
Natural gas revenues for the successor year-to-date 2017 included recovery of $951 million in cost of natural gas and $119 million in net revenues from wholesale gas services. Also included in natural gas revenues was $45 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and a $15 million decrease attributable to warmer-than-normal weather, net of hedging.
Natural gas revenues for the predecessor year-to-date 2016 reflected recovery of $755 million in cost of natural gas 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.
See "Segment Information""Segment Information" herein for additional information on wholesale gas services' revenues and losses.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations. See "Cost"Cost of Natural Gas"Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
During Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact during the non-Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
 Second Quarter 2017
vs.
2016
 2017
vs.
normal
 Year-to-Date 2017
vs.
2016
 2017
vs.
normal
 Year-to-Date 2017
vs.
2016
 2017
vs.
normal
 
Normal(a)
 2017 2016 (warmer) (warmer) 
Normal(a)
 2017 2016 (warmer) (warmer) 
Normal(a)
 2017 2016 (warmer) (warmer)
Illinois(b)
 639
 555
 639
 (13)% (13)% 3,760
 3,110
 3,340
 (7)% (17)% 3,817
 3,146
 3,353
 (6.2)% (17.6)%
Georgia 137
 75
 114
 (34)% (45)% 1,636
 1,000
 1,448
 (31)% (39)% 1,631
 1,008
 1,449
 (30.4)% (38.2)%
(a)Normal represents the 10-year average from January 1, 2007 through JuneSeptember 30, 2016 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 617 for the second quarter and 3,5193,580 for the first sixnine months from 1998 through 2007.
For the successor second quarterthird quarters 2017 and 2016, the predecessor second quarter 2016,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 on gas distribution operations was limited to $2$6 million ($3 million after tax) and $7 million ($5 million after tax) for year-to-date 2017 and 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in each period.Georgia and Illinois;

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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 on gas distribution operations was limited to $5 million ($3 million after tax) and $7 million ($5 million after tax) for the successor year-to-date 2017 and the predecessor year-to-date 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in Georgia; therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for the successor year-to-date 2017 and there was no impact for the predecessor year-to-date 2016.
The following table provides the number of customers served by Southern Company Gas at JuneSeptember 30, 2017 and 2016:
June 30,  September 30,  
2017 2016 2017 vs. 20162017 2016 2017 vs. 2016
(in thousands, except market share %) (% change)(in thousands, except market share %) (% change)
Gas distribution operations4,573
 4,544
 0.6 %4,555
 4,522
 0.7 %
Gas marketing services          
Energy customers(*)
768
 630
 21.9 %756
 626
 20.8 %
Market share of energy customers in Georgia29.1% 29.3%  28.8% 29.4%  
Service contracts1,188
 1,197
 (0.8)%1,183
 1,189
 (0.5)%
(*)Includes approximately 140,000 customers as of JuneSeptember 30, 2017 that were contracted to serve beginning April 1, 2017.
Southern Company Gas anticipates overall customer growth trends at gas distribution operations to continue in 2017, as it expects continued improvement in the new housing market and low natural gas prices.
Gas marketing services' market share in Georgia decreased slightly at JuneSeptember 30, 2017 compared to June 30,the corresponding period in 2016 as a result of a highly competitive marketing environment, which Southern Company Gas expects to continue 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.
Cost of Natural Gas
Cost
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 $232$134 million compared to $133 million for the successor second quarter 2017 and $184 million for the predecessor second quarter 2016, which primarilycorresponding period in 2016. This increase reflected an increase of 63% in7% higher natural gas prices during the successor secondthird quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.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 was $951 million for the successor year-to-date 2017 and $755 million for the predecessor year-to-date 2016, which primarily reflected an increase of 61%38% in natural gas prices during the successor 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.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the 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% of total cost of natural gas for year-to-date 2017 and will be recovered in this manner. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural"Natural Gas Revenues"Revenues" herein.

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The following table details the volumes of natural gas sold during all periods presented.
Second Quarter 2017
vs.
2016
 Year-to-Date 2017
vs.
2016
Third Quarter 2017
vs.
2016
 Year-to-Date 2017
vs.
2016
2017 2016 % Change 2017 2016 % Change2017 2016 % Change 2017 2016 % Change
Gas distribution operations
(mmBtu in millions)
                      
Firm102
 107
 (4.7)% 365
 396
 (7.8)%73
 71
 2.8 % 438
 467
 (6.2)%
Interruptible23
 22
 4.5 % 48
 49
 (2.0)%22
 22
  % 71
 71
  %
Total125
 129
 (3.1)% 413
 445
 (7.2)%95
 93
 2.2 % 509
 538
 (5.4)%
Gas marketing services
(mmBtu in millions)
                      
Firm:                      
Georgia4
 4
  % 17
 21
 (19.0)%3
 3
  % 11
 25
 (56.0)%
Illinois2
 2
  % 7
 8
 (12.5)%1
 1
  % 4
 8
 (50.0)%
Other emerging markets3
 2
 50.0 % 8
 7
 14.3 %2
 2
  % 7
 9
 (22.2)%
Interruptible:                      
Large commercial and industrial3
 4
 (25.0)% 7
 8
 (12.5)%3
 3
  % 8
 10
 (20.0)%
Total12
 12
  % 39
 44
 (11.4)%9
 9
  % 30
 52
 (42.3)%
Wholesale gas services
(mmBtu in millions/day)
                      
Daily physical sales6.2
 7.2
 (13.9)% 6.4
 7.6
 (15.8)%6.3
 7.6
 (17.1)% 6.4
 7.6
 (15.8)%
Other Operations and Maintenance Expenses
Other
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$(11) (5.1)
In the third quarter 2017, other operations and maintenance expenses were $213$205 million compared to $216 million for both the successor second quarter 2017corresponding period in 2016. The decrease was primarily related to $8 million of expenses associated with certain benefit arrangements recorded in 2016, $2 million lower marketing expenses at gas marketing services, and the predecessor second quarter 2016.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 expenses were $467 million for the successor year-to-date 2017 and $454 million for the predecessor year-to-date 2016. Other operations and maintenance expense for the successor year-to-date period reflected increased compensation expenses and pipeline and maintenance expenses,due to timing, partially offset by low bad debt expense.
Depreciation and Amortization
Depreciation and amortization was $125 million for the successor second quarter 2017 and $104 million for the predecessor second quarter 2016. The successor second quarter 2017 included $9 million of additional net amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas midstream For all periods presented, other operations and gas distribution operations,maintenance expenses primarily includes professional services, including pipeline compliance and maintenance and legal services, as well as $7 million in additional depreciation at gas distribution operations due to a $1.1 billion increase in gross property, plant,compensation and equipment since June 30, 2016.
Depreciation and amortization was $244 million for the successor year-to-date 2017 and $206 million for the predecessor year-to-date 2016. The successor year-to-date 2017 included $19 million of additional net amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas midstream operations and gas distribution operations, as well as $13 million in additional depreciation at gas distribution operations due to additional assets placed in service.
Taxes Other Than Income Taxes
For the successor second quarter 2017 and the predecessor second quarter 2016, taxes other than income taxes were $44 million and $37 million, respectively. For the successor year-to-date 2017 and the predecessor year-to-datebenefit costs.

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2016,Depreciation and Amortization
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$9 7.8
In the third quarter 2017, depreciation and amortization was $125 million compared to $116 million for the corresponding period in 2016. The increase was primarily due to $7 million in additional depreciation 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 additional amortization of intangible assets established in the application of acquisition accounting primarily at gas marketing services, $21 million in additional depreciation at gas distribution operations due to additional assets placed in service primarily related to continued investment in infrastructure replacement programs, and $7 million from the acceleration of depreciation relating to certain assets.
Taxes Other Than Income Taxes
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$(3) (10.3)
In the third quarter 2017, taxes other than income taxes were $114$26 million and $99compared to $29 million respectively. Taxes other than income taxes consistfor the corresponding period in 2016. The decrease primarily of revenue tax expenses, property taxes, and payroll taxes. reflects establishing 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.operations during the successor periods.

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Earnings from Equity Method Investments
For
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$3 10.3
In the successor secondthird quarter 2017, earnings from equity method investments were $32 million compared to $29 million whichfor the corresponding period in 2016. The increase was 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 from equity method investments in the successor year-to-date 2017 consisted of $24$86 million in earnings from SNG and $5$14 million in earnings from all other investments. For the predecessor second quarter 2016, earnings from equity method investments were not material.
For the successor year-to-date 2017, earnings from equity method investments were $68 million, which consisted of $58 million in earnings from SNG and $10 million in earnings from all other investments. For the predecessor year-to-date 2016, earnings from equity method investments were not material.
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) to the Condensed Financial Statements under "Southern Company GasEquity 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.

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Interest Expense, Net of Amounts Capitalized
For both
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions) (% change)
$12 30.8
In the successor secondthird quarter 2017, and the predecessor second quarter 2016, interest expense, net of amounts capitalized was $48 million. $51 million compared to $39 million for the corresponding period in 2016. The 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 second quarteryear-to-date 2017 reflects a $10and the period of July 1, 2016 through September 30, 2016 reflect additional interest expense on new debt issuances, partially offset by reductions of $29 million reductionand $9 million, respectively, resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by $6accounting.
Income Taxes
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)(% change)
$45N/M
N/M - Not meaningful
In the third quarter 2017, income taxes were $52 million compared to $7 million for the corresponding period in 2016. The increase reflects $23 million of additional interestdeferred income tax expense on new debt issuances in 2017 and 2016.
Forassociated with State of Illinois tax legislation enacted during the successor year-to-datethird quarter 2017 and the predecessor year-to-date 2016, interest expense, netallocation of amounts capitalized was $94 million and $96 million, respectively. new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, as well as higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL 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 reflects a $19 million reduction resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by $12income taxes reflect $23 million of additional interestdeferred income tax expense on new debt issuances in 2017 and 2016.
Income Taxes (Benefit)
For the successor second quarter 2017associated with State of Illinois tax legislation and the predecessor second quarter 2016,allocation of new tax apportionment factors, as well as increased income taxes (benefit) were $31 million and $(24) million, respectively, driven byfrom higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.
For the successor year-to-date 2017 and the predecessor year-to-date 2016, income taxes were $180 million and $87 million, respectively, driven by pre-tax earnings and the non-deductibility of certain Merger-related expenses.
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

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(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 second quarterthird 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 second quarterthird quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to the 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.

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Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and Merger-related expenses, 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 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 adjusted operating margin should not be considered alternatives to, or more meaningful indicators 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 Successor  Predecessor Successor  Predecessor
Second Quarter 2017  Second Quarter 2016 Year-to-Date 2017  Year-to-Date 2016 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) (in millions)  (in millions) (in millions)  (in millions)
Operating Income$96
  $(27) $487
  $321
 $68
 $12
 $555
 $12
  $321
Other operating expenses(a)
382
  407
 825
  815
 356
 396
 1,181
 396
  815
Revenue taxes(b)
(18)  (17) (65)  (56) (8) (8) (74) (8)  (56)
Adjusted Operating Margin$460
  $363
 $1,247
  $1,080
 $416
 $400
 $1,662
 $400
  $1,080
(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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 Successor  Predecessor Successor  Predecessor
 Second Quarter 2017  Second Quarter 2016 Year-to-Date 2017  Year-to-Date 2016
 (in millions)  (in millions) (in millions)  (in millions)
Consolidated Net Income (Loss) Attributable to Southern Company Gas$49
  $(51) $288
  $131
Net income attributable to noncontrolling interest (*)

  3
 
  14
Income taxes31
  (24) 180
  87
Interest expense, net of amounts capitalized48
  48
 94
  96
EBIT$128
  $(24) $562
  $328
  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
(*)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.

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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

PredecessorSuccessor
Second Quarter 2017

Second Quarter 2016Third Quarter 2017
Third Quarter 2016

 Adjusted Operating
Operating
Net

Adjusted Operating
Operating

 Adjusted Operating
Operating
Net Income
Adjusted Operating
Operating
Net Income

Margin(*)

Expenses(*)

Income

Margin(*)

Expenses(*)

EBIT
Margin(*)

Expenses(*)

(Loss)
Margin(*)

Expenses(*)

(Loss)

(in millions)

(in millions)(in millions)
(in millions)
Gas distribution operations$409

$283

$54


$386

$269

$118
$379

$271

$52

$353

$284

$27
Gas marketing services57

48

4


66

37

29
51

48

1

45

51

(4)
Wholesale gas services(13)
14

(17)

(96)
16

(112)(25)
11

(23)
(8)
10

(11)
Gas midstream operations7

13

9


6

12

(5)12

13

14

9

13

14
All other3

9

(1)

2

58

(55)2

8

(29)
2

31

(22)
Intercompany eliminations(3)
(3)



(1)
(2)
1
(3)
(3)


(1)
(1)

Consolidated$460

$364

$49


$363

$390

$(24)$416

$348

$15

$400

$388

$4
(*)Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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 Successor  Predecessor
 Year-to-Date 2017  Year-to-Date 2016
  Adjusted Operating Operating Net  Adjusted Operating Operating  
 
Margin(*)
 
Expenses(*)
 Income  
Margin(*)
 
Expenses(*)
 EBIT
 (in millions)  (in millions)
Gas distribution operations$951
 $596
 $171
  $911
 $560
 $353
Gas marketing services162
 101
 35
  190
 81
 109
Wholesale gas services118
 29
 51
  (36) 33
 (68)
Gas midstream operations16
 25
 25
  15
 24
 (6)
All other5
 14
 6
  4
 65
 (60)
Intercompany eliminations(5) (5) 
  (4) (4) 
Consolidated$1,247
 $760
 $288
  $1,080
 $759
 $328
 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
(*)Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.
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. 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 utilities' service territories.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net income was $52 million compared to $27 million for the corresponding period in 2016. The increase in net income relates to an increase of $26 million 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 in other income (expense), net primarily reflects a $14 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 primarily 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 in operating expenses, and $23 million in other income (expense), net, which resulted in EBIT of $486 million. Net income also includes

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Successor Second Quarter 2017
Net income of $54 million includes $409 million in adjusted operating margin, $283 million in operating expenses, and $2 million in other income (expense), net, which resulted in EBIT of $128 million. Net income also includes $40$119 million in interest expense, net of amounts capitalized and $34$144 million in income tax expense. Adjusted operating margin reflects $26 million in additional revenue from the continued investment in infrastructure replacement programs, a base rate increase at Atlanta Gas Light effective March 1, 2017, and a $1 million positive impact of weather, net of hedging, despite warmer-than-normal weather. Operating expenses reflect additional depreciation due to continued investment in infrastructure programs and increased pipeline compliance and maintenance activities.
Predecessor Second Quarter 2016
EBIT of $118 million includes $386 million in adjusted operating margin, $269 million in operating expenses, and $1 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $1 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.
Successor Year-to-Date 2017
Net income of $171 million includes $951 million in adjusted operating margin, $596 million in operating expenses, and $6 million in other income (expense), net, which resulted in EBIT of $361 million. Net income also includes $80 million in interest expense and $110 million in income tax expense. Adjusted operating margin reflects $45$69 million in additional revenue from continued investment in infrastructure replacement programs and a base rate increaseincreases, primarily at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth, partially offset by a $5$6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $13$21 million increase in depreciation associated with additional assets placed in service, as well as increased compensation expense, legal expenses, and pipeline compliance and maintenance activities. Other income (expense), net reflects a $16 million gain from the settlement of contractor litigation claims. Interest expense reflects the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017.
Successor Period of July 1, 2016 through September 30, 2016
Net income of $27 million includes $353 million 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 Year-to-DatePeriod 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, partially offset by a $7 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.
Gas Marketing Services
Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets, including warranty sales. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.
Successor SecondThird Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net income was $1 million compared to a net loss of $4 million for the corresponding period in 2016. The increase in net income primarily relates to a $6 million increase in adjusted operating margin and a $3 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, and a $4 million increase from the elimination of deferred revenue 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.
Successor Year-to-Date 2017
Net income of $4$36 million includes $57$213 million in adjusted operating margin and $48$149 million in operating expenses, which resulted in EBIT of $9$64 million. Net income also includes $2$4 million in interest expense and $3$24 million in income tax expense. Adjusted operating margin reflects a $3$10 million negative impact of warmer-than-normal weather, net of hedging.hedging, and $7 million in unrealized hedge losses, net of recoveries. Operating expenses reflect $10include $30 million in additional amortization of intangible assets due to fair value adjustments to certain assets and liabilitiesestablished in the application of acquisition accounting.
Predecessor Second QuarterSuccessor Period of July 1, 2016 through September 30, 2016
EBITNet loss of $29$4 million includes $66$45 million in adjusted operating margin and $37$51 million in operating expenses. Adjusted operating margin reflects $7expenses, which resulted in a loss before interest and taxes of $6 million. Also included in net loss is $2 million in unrealized hedge gains and a $1 million negative impact ofincome tax benefit.

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weather, netPredecessor Period of hedging. Earnings in the predecessor period include $3 million attributable to noncontrolling interest.
Successor Year-to-Date 2017
Net income of $35 million includes $162 million in adjusted operating margin and $101 million in operating expenses, which resulted in EBIT of $61 million. Net income also includes $3 million in interest expense and $23 million in income tax expense. Adjusted operating margin reflects $2 million of additional revenue as a result of fair value adjustments to certain assets and liabilities in the application of acquisition accounting, as well as a $10 million negative impact of warmer-than-normal weather, net of hedging and $7 million in unrealized hedge losses. Operating expenses also reflect $20 million in additional amortization of intangible assets due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting.
Predecessor Year-to-DateJanuary 1, 2016 through June 30, 2016
EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Earnings in the predecessor period include $14 million attributable to noncontrolling interest.
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.
Successor SecondThird Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net loss was $23 million compared to a net loss of $11 million for the corresponding period in 2016. The increase in net loss relates primarily to a $17 million decrease in adjusted operating margin, partially offset by an increase of $8 million in income tax benefit due to higher losses. The decrease in adjusted gross margin includes $22 million in additional mark-to-market losses and a $7 million decrease in gains from commercial activity, partially offset by a $12 million positive impact from the amortization of liabilities recorded in the application of acquisition accounting.
Successor Year-to-Date 2017
Net lossincome of $17$28 million includes $(13)$93 million in adjusted operating margin and $14$40 million in operating expenses, which resulted in EBIT of $53 million. Net income also includes $5 million in interest expense and $20 million in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
Net loss of $11 million includes $(8) million in adjusted operating margin and $10 million in operating expenses, which resulted in a loss before interest and taxes of $27$17 million. Also included in net loss is $1 million in interest expense and $11$7 million in income tax benefit.
Predecessor Second QuarterPeriod of January 1, 2016
Loss before interest and taxes of $112 million includes $(96) million in adjusted operating margin and $16 million in operating expenses.
Successor Year-to-Date 2017
Net income of $51 million includes $118 million in adjusted operating margin and $29 million in operating expenses, which resulted in EBIT of $89 million. Net income also includes $3 million in interest expense and $35 million in income tax expense.
Predecessor Year-to-Date 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.

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The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.
Successor

Predecessor Successor  PredecessorSuccessor  Predecessor
Second Quarter 2017  Second Quarter 2016 Year-to-Date 2017  Year-to-Date 2016Third 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) (in millions)  (in millions)(in millions)  (in millions)
Commercial activity recognized$(18)  $(8) $69
  $34
$3
 $10
 $80
 10
  $34
Gain (loss) on storage derivatives17
  (36) 18
  (38)4
 11
 13
 11
  (38)
Gain (loss) on transportation and forward commodity derivatives(2)  (52) 37
  (31)(22) (7) 14
 (7)  (31)
LOCOM adjustments, net of current period recoveries(1)  
 (1)  (1)
 
 
 
  (1)
Impact of purchase accounting adjustments(9)  
 (5)  
Purchase accounting adjustments(10) (22) (14) (22)  
Adjusted Operating Margin$(13)  $(96) $118
  $(36)$(25) $(8) $93
 $(8)  $(36)
Change in Commercial Activity
The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and build-out of new U.S. pipeline infrastructure, along with increases in 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.
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 sixnine months of 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing 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-normal 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

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charges, but are net of the 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 JuneSeptember 30,

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2017. 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  Storage withdrawal schedule  
Total storage
(WACOG $2.75)
 
Expected net operating gains(a)
 
Physical transportation transactions – expected net operating losses(b)
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)(in mmBtu in millions) (in millions) (in millions)
201736.5
 $5
 $(10)22.0
 $4
 $(13)
2018 and thereafter30.9
 12
 (27)40.0
 17
 28
Total at June 30, 201767.4
 $17
 $(37)
Total at September 30, 201762.0
 $21
 $15
(a)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)Represents the periods associated with the transportation derivative gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.
The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.
Gas Midstream Operations
Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments consist of theinclude SNG, interest, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. 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.
Successor SecondThird Quarter 2017 vs. Third Quarter 2016
In both the third quarter 2017 and the corresponding period in 2016 net income was $14 million. Net income reflects a $3 million increase in adjusted operating margin and a $4 million increase in earnings from equity method investments at SNG, PennEast Pipeline, and Horizon Pipeline. The change in net income also includes a $9 million increase in interest expense, net of amounts capitalized and a $2 million decrease in income taxes. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016.
Successor Year-to-Date 2017
Net income of $9$38 million includes $7$28 million in adjusted operating margin, $38 million in operating expenses, $97 million in earnings from equity method investments, consisting primarily of earnings from equity method investments at SNG, and $3 million in other income (expense), net, which resulted in EBIT of $90 million. Also included in net income are $25 million in interest expense and $27 million in income tax expense.
Successor Period of July 1, 2016 through September 30, 2016
Net income of $14 million includes $9 million in adjusted operating margin, $13 million in operating expenses, $28 million in earnings from equity method investments, which consistsconsisting primarily of equity in earnings from the investment inequity method

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investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of $23$25 million. Also included in net income are $8 million in interest expense and $6is $11 million in income tax expense.
Predecessor Second QuarterPeriod of January 1, 2016
Loss before interest and taxes of $5 million includes $6 million in adjusted operating margin, $12 million in operating expenses, and $1 million of other income (expense), net.
Successor Year-to-Date 2017
Net income of $25 million includes $16 million in adjusted operating margin, $25 million in operating expenses, $66 million in earnings from equity method investments, which consists primarily of equity in earnings from the investment in SNG, and $2 million in other income (expense), net, which resulted in EBIT of $59 million. Also included in net income are $17 million in interest expense and $17 million in income tax expense.
Predecessor Year-to-Date 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.

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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.
Successor Third Quarter 2017 vs. Third Quarter 2016
In the third quarter 2017, net loss was $29 million compared to $22 million in the corresponding period in 2016. The increase in net loss reflects a $23 million decrease 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 million increase in other operations and maintenance expenses and a $3 million increase from the acceleration of depreciation relating to certain assets. Interest expense decreased as a result of intercompany promissory notes executed in December 2016. The increase in income taxes primarily reflects additional deferred income tax expenses associated with State of Illinois tax legislation enacted during the third quarter 2017, as well as 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.
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 and income tax benefit was $11 million and $35 million, respectively, 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 successor second quarter or year-to-date 2017. Forinclusion of Southern Company Gas into the predecessor second quarter 2016 and year-to-date 2016, Merger-related expenses included in operating expenses were $53 million and $56 million, respectively.consolidated Southern Company state tax filings.

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

SuccessorSuccessor

Second Quarter 2017Third 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)
Consolidated Net Income$54
$4
$(17)$9
$(1)$
$49
Income taxes34
3
(11)6
(1)
31
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
40
2
1
8
(3)
48
39
1
2
9


51
EBIT$128
$9
$(27)$23
$(5)$
$128
$125
$3
$(36)$32
$(6)$
$118
Successor Successor
Year-to-Date 2017 Third Quarter 2016
Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
(in millions) (in millions)
Consolidated Net Income$171
$35
$51
$25
$6
$
$288
Income taxes110
23
35
17
(5)
180
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
80
3
3
17
(9)
94
 32

1

6

39
EBIT$361
$61
$89
$59
$(8)$
$562
 $75
$(6)$(17)$25
$(27)$
$50

Successor

Second Quarter 2017

Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated

(in millions)
Operating Income (Loss)$126
$9
$(27)$(6)$(6)$
$96
Other operating expenses(a)
301
48
14
13
9
(3)382
Revenue tax expense(b)
(18)




(18)
Adjusted Operating Margin$409
$57
$(13)$7
$3
$(3)$460
 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

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SuccessorSuccessor
Year-to-Date 2017Third 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)$355
$61
$89
$(9)$(9)$
$487
$108
$3
$(36)$(1)$(6)$
$68
Other operating expenses(a)
661
101
29
25
14
(5)825
279
48
11
13
8
(3)356
Revenue tax expense(b)
(65)




(65)(8)




(8)
Adjusted Operating Margin$951
$162
$118
$16
$5
$(5)$1,247
$379
$51
$(25)$12
$2
$(3)$416

PredecessorSuccessor

Second Quarter 2016Third Quarter 2016

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)$117
$29
$(112)$(6)$(56)$1
$(27)$69
$(6)$(18)$(4)$(29)$
$12
Other operating expenses(a)
286
37
16
12
58
(2)407
292
51
10
13
31
(1)396
Revenue tax expense(b)
(17)




(17)(8)




(8)
Adjusted Operating Margin$386
$66
$(96)$6
$2
$(1)$363
$353
$45
$(8)$9
$2
$(1)$400
PredecessorSuccessor
Year-to-Date 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
$463
$64
$53
$(10)$(15)$
$555
Other operating expenses(a)
616
81
33
24
65
(4)815
940
149
40
38
22
(8)1,181
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
 Predecessor
 January 1, 2016 through June 30, 2016
 Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
 (in millions)
Operating Income (Loss)$351
$109
$(69)$(9)$(61)$
$321
Other operating expenses(a)
616
81
33
24
65
(4)815
Revenue tax expense(b)
(56)




(56)
Adjusted Operating Margin$911
$190
$(36)$15
$4
$(4)$1,080
(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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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 its primary business of natural gas distribution and complementary businesses in the gas marketing services, wholesale gas services, and gas midstream operations sectors. These factors include Southern Company Gas' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, Southern Company Gas' 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 maintaining and growing sales and customers which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced

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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 economic growth. Thethe pace of economic growth and natural gas demandthat 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 will requirerequired Southern Company Gas to adjust existingincrease accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect an increased tax rate,these changes, $15 million of which was expensed and any portion not recoverable through rates will impact earnings.$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 evaluating these changes.being performed with the assistance of a third-party valuation specialist. The ultimate impactpreliminary results of this legislation cannot be determinedvaluation indicate that the estimated fair values of the reporting units with goodwill exceed their carrying amounts and are not at this time, but could have a material impactrisk 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 Southern Company Gas' financial statements.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, 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.

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For additional information relating to these issues, see "Risk Factors" of Southern Company Gas in Item 1A of the Form 10-K.
In September 2016, Southern Company Gas acquired a 50% equity interest in SNG. See OVERVIEW – "Merger and Acquisition Activities" and 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. 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.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and financial condition. See Note (B) under ""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.

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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.
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, the Atlantic Coast Pipeline project received FERC approval.
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 MattersSouthern 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 by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism.mechanism based on amounts approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.

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Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE 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, and Integrated Customer Growth Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be 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, 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 increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on 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.

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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. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit,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 in annual base rate revenues. The requested increase iswas based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase includesincluded $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 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

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change in base rates. The Virginia Commission is expected to rule on the requested increaseproposed stipulation in the firstfourth quarter 2018.2017. Rate adjustments are expected to bebased 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 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, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $75$178 million of qualifying assets during the first sixnine months of 2017.
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 liquefied natural gasLNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $94$127 million during the first sixnine 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.
The recovery of and return on current and future capital investments under Subsequently, the STRIDE program will be included in the annual base rate revenue adjustment under GRAM rather than a separate surcharge. The proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM that was 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 $12$16 million during the first sixnine 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 extension to the SAVE program, under which Virginia Natural Gas invested $14$21 million during the first sixnine months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' Safety, Access, and Facility EnhancementSAFE program in 2015. Under the program, Florida City Gas invested $7$9 million during the first sixnine months of 2017.

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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

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ordinary course of business. The ultimate outcome of such pending or potential litigation against Southern Company Gasor 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 defendants in a putative class action initially filed 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, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company Gas' financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in 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.
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.
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. The new standard also requires enhanced disclosures 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.
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

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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, the FASB issued ASU No. 2017-04,Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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(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 income statement outside 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. 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. Southern Company Gas is currently evaluating the new standard. 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 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company Gas' financial statements.

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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 secondthird quarter and year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor second quarter and year-to-dateperiod of January 1, 2016 through June 30, 2016. See OVERVIEW – "Merger, Acquisition, and AcquisitionDisposition Activities" and Note (I) to the Condensed Financial Statements under "Southern"Southern CompanyMerger with Southern Company Gas"Gas" herein for additional information.

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Southern Company Gas' financial condition remained stable at JuneSeptember 30, 2017. 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 of JuneSeptember 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $739$752 million. These restrictions 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 $1.2$1.1 billion for the successor first sixnine months of 2017, $(342) million for the successor period of July 1, 2016 through September 30, 2016, and $1.1 billion for the predecessor first six monthsperiod of January 1, 2016 through June 30, 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.
Net cash used for investing activities totaled $781 million$1.2 billion for the successor first sixnine months of 2017, primarily due 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 first six monthsperiod 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.operations and the acquisition of Southern Company Gas' ownership interest in SNG in September 2016.
Net cash used forprovided from financing activities totaled $351$45 million for the successor first sixnine months of 2017, primarily due to proceeds from debt issuances and capital contributions from Southern Company, partially offset by net repayments of commercial paper borrowings and common stock dividend payments to Southern Company, partially offset by proceeds from debt issuances and capital contributions from Southern Company. Net cash used forprovided from (used for) financing activities totaled $558$2.1 billion for the successor period of July 1, 2016 through September 30, 2016 and $(558) million for the predecessor first six monthsperiod 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.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.

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Significant balance sheet changes at JuneSeptember 30, 2017 include an increase of $514$847 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase in long-term debt of $418$603 million primarily due to $450 million of senior notes and $200 million of first mortgage bonds at Nicor Gas issued in May 2017 and decreasesAugust 2017, respectively, and a decrease of $223 million in natural gas for sale, including temporary LIFO liquidation due to the use of natural gas stored during the first six months of 2017, and $631$323 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include an increase of $239 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and decreases of $141$196 million and $63$146 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.
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, scheduled 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. Approximately $22 million will be required through June 30, 2018 to fundThere are no scheduled maturities of long-term debt.debt through September 30, 2018. See "Sources of Capital" herein for additional information.

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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, 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, and other factors. 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 JuneSeptember 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $572$645 million primarily as a result of $626$934 million in notes payable. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company 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.

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


At JuneSeptember 30, 2017, Southern Company Gas had approximately $38$21 million of cash and cash equivalents. Committed credit arrangements with banks at JuneSeptember 30, 2017 were as follows:
Expires  
Company2022 Unused Expires 2022 Unused
(in millions) (millions)
Southern Company Gas Capital$1,200
 $1,149
 $1,200
 $1,161
Nicor Gas700
 700
 700
 700
Total$1,900
 $1,849
 $1,900
 $1,861
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.
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) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
As reflected in the table above, inIn 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 (Facility) currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022.
The Facility included2022, as reflected in the table aboveabove. 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) 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS


June September 30, 2017, each of the applicableboth companies waswere 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.
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-termcommercial paper borrowings were as follows:
Short-term Debt at
June 30, 2017
 
Short-term Debt During the Period(*)
Commercial Paper at September 30, 2017 
Commercial Paper 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$581
 1.5% $558
 1.3% $750
$836
 1.5% $680
 1.5% $838
Nicor Gas45
 1.4
 143
 1.2
 308
98
 1.3
 40
 1.3
 120
Short-term loans:         
Southern Company Gas
 
 
 4.0
 40
Total$626
 1.5% $701
 1.3%  $934
 1.5% $720
 1.5%  
(*)Average and maximum amounts are based upon daily balances during the successor three-month period ended JuneSeptember 30, 2017.
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.

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


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 requirements under these contracts at JuneSeptember 30, 2017 were $9$12 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets, and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
Financing Activities
The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of JuneSeptember 30, 2017, the non-principal components totaled $537$523 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, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Subsequent to June 30,In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.
Subsequent to June 30,In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds in a private placement,3.03% 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 of which is expected to be issued in each of August 2017 and November 2017.
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 secondthird quarter and year-to-date 2017. 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) and (H) 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.

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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 illustrates the change 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 outstanding as of the dates presented.
Successor  Predecessor Successor  Predecessor Successor  Predecessor
Second Quarter  Second Quarter Year-to-Date  Year-to-Date Third Quarter Third Quarter Year-to-Date July 1, 2016 through September 30, 2016  January 1, 2016
through
June 30,
2016
2017  2016 2017  2016 2017 2016 2017   
(in millions)  (in millions) (in millions)  (in millions) (in millions)  (in millions)
Contracts outstanding at beginning of period, assets (liabilities), net$64
  $(44) $12
  $75
 $51
 $(54) $12
 $(54)  $75
Contracts realized or otherwise settled(20)  8
 (16)  (77) (6) (3) (22) (3)  (77)
Current period changes(a)
7
  (48) 55
  (82) (16) 
 39
 
  (82)
Contracts outstanding at the end of period, assets (liabilities), net51
  (84) 51
  (84) 29
 (57) 29
 (57)  (84)
Netting of cash collateral71
  120
 71
  120
 76
 111
 76
 111
  120
Cash collateral and net fair value of contracts outstanding at end of period(b)
$122
  $36
 $122
  $36
 $105
 $54
 $105
 $54
  $36
(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 instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $11$13 million at JuneSeptember 30, 2017 and $5$7 million at JuneSeptember 30, 2016.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The maturities of Southern Company Gas' energy-related derivative contracts at JuneSeptember 30, 2017 were as follows:
  Fair Value Measurements  Fair Value Measurements
  Successor – June 30, 2017  Successor – September 30, 2017
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)
$(12) $5
 $(14) $(3)$(35) $(10) $(20) $(5)
Level 2(b)
63
 27
 30
 6
64
 12
 45
 7
Fair value of contracts outstanding at end of period(c)
$51
 $32
 $16
 $3
$29
 $2
 $25
 $2
(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 $71$76 million at JuneSeptember 30, 2017.

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


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





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


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, 2016 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 JuneSeptember 30, 2017 and 2016. 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 sixnine months ended JuneSeptember 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of JuneSeptember 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 Issued 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.
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. The new standard also 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 be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, 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 result 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 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 the registrants' financial statements, the registrants will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04,Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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 and Southern Company Gas are evaluating the standard and expect 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 (ASU

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

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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible

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

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. Southern Company, the traditional electric operating companies, and Southern Company Gas are currently evaluating the new standard. 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 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, the traditional electric operating companies', or 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 2017-12 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 adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.
Affiliate Transactions
Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, 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 conditions of SNG's natural gas tariff and is subject to FERC regulation. For the sixnine months ended JuneSeptember 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $4$8 million, $51$77 million, $13$19 million, and $16$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 sixnine months ended JuneSeptember 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $9$18 million and $56$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.

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

Goodwill and Other Intangible Assets
At JuneSeptember 30, 2017 and December 31, 2016, goodwill was as follows:
GoodwillGoodwill
At June 30, 2017At December 31, 2016At September 30, 2017At December 31, 2016
(in millions)(in millions)
Southern Company$6,271
$6,251
$6,267
$6,251
Southern Power$2
$2
$2
$2
Southern Company Gas  
Gas distribution operations$4,702
$4,702
$4,702
$4,702
Gas marketing services1,265
1,265
1,265
1,265
Southern Company Gas total$5,967
$5,967
$5,967
$5,967
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 June 30, 2017 At December 31, 2016At September 30, 2017 At December 31, 2016
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
$(57)$231
 $268
$(32)$236
$288
$(70)$218
 $268
$(32)$236
Trade names159
(11)148
 158
(5)153
159
(15)144
 158
(5)153
Patents4

4
 4

4
Backlog5
(1)4
 5
(1)4
Storage and transportation contracts64
(21)43
 64
(2)62
64
(27)37
 64
(2)62
Software and other4
(1)3
 2

2
PPA fair value adjustments456
(35)421
 456
(22)434
456
(41)415
 456
(22)434
Other16
(3)13
 11
(1)10
Total other intangible assets subject to amortization$980
$(126)$854
 $957
$(62)$895
$983
$(156)$827

$957
$(62)$895
Other intangible assets not subject to amortization:      
Federal Communications Commission licenses$75
$
$75
 $75
$
$75
$75
$
$75
 $75
$
$75
Total other intangible assets$1,055
$(126)$929
 $1,032
$(62)$970
$1,058
$(156)$902
 $1,032
$(62)$970
      
Southern Power      
Other intangible assets subject to amortization:      
PPA fair value adjustments$456
$(35)$421
 $456
$(22)$434
$456
$(41)$415
 $456
$(22)$434
      
Southern Company Gas      
Other intangible assets subject to amortization:      
Gas marketing services      
Customer relationships$221
$(53)$168
 $221
$(30)$191
$221
$(65)$156
 $221
$(30)$191
Trade names115
(6)109
 115
(2)113
115
(8)107
 115
(2)113
Wholesale gas services      
Storage and transportation contracts64
(21)43
 64
(2)62
64
(27)37
 64
(2)62
Total other intangible assets subject to amortization$400
$(80)$320
 $400
$(34)$366
$400
$(100)$300
 $400
$(34)$366

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

Amortization associated with other intangible assets was as follows:
Three Months EndedSix Months EndedThree Months EndedNine Months Ended
June 30, 2017September 30, 2017
(in millions)(in millions)
Southern Company$29
$65
$29
$94
Southern Power$6
$13
$6
$19
Southern Company Gas$20
$46
$20
$66
See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) under "Southern Company Acquisition of PowerSecure" and " Merger with Southern Company Gas" for additional information.
Property Damage Reserve
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.
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 butand 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 events 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 stormproperty damage reserve to approximately $40 million. As of 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.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas'Gas had no inventory decrement at JuneSeptember 30, 2017 is expected to be restored prior to year end.2017. 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.

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(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 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 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
On January 20, 2017, a purported 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 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.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 defendants Southern Company, certain of its directors, 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' 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 thatand, 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. TheEach 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. TheEach 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. TheEach plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys'

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and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. TheEach plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.
On June 1,August 15, 2017, Judy Mesirov filed athese two shareholder derivative lawsuitlawsuits were consolidated in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company,and the court deferred the consolidated case until 30 days after certain of its current and former directors, certain of its officers, and certain former Mississippi Power officers. Thefurther action in the purported securities class action 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. The 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. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages, disgorgement of profits, and equitable relief and, on her own 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.discussed above.
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.
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 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 has filed a petition for writ of certiorari with the Georgia Supreme Court.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 lien 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.

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Southern Company Gas
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of 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 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

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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, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.
Environmental Matters
Environmental RemediationSettled Base Rate Cases
The Southern Company system must comply with environmental lawsOn February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and regulations that covera $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the handlingpreviously approved ROE of 10.75% and disposal of wastedoes not collect revenue through special riders and releases of hazardous substances. Under these various lawssurcharges. 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 regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companiesIntegrated System Reinforcement Program, will continue under GRAM and the natural gas distribution utilitiesrecovery of and return on the infrastructure program investments will be included in Illinois,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 Georgia,BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 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 $12 million and $17 million asa ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on 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. The requested increase is based on a 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, 2016, respectively. Georgia Power has been designated or identified as2017, Virginia Natural Gas filed a potentially responsible party at sites governed bygeneral base rate case with 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 $51 million andVirginia Commission requesting a $44 million as of June 30,increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and December 31, 2016, respectively. These estimated costs primarily relatea ROE of 10.25%. The requested increase included $13 million related to site closure criteria by the Florida Departmentrecovery of Environmental Protection (FDEP) for potential impactsinvestments under the Steps to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completionAdvance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the remediation projectsVirginia 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

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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 FDEP approval. The projects have been approved byrefund.
On October 23, 2017, Florida City Gas filed a general base rate case with 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 $416requesting a $19 million and $426 million as of June 30, 2017 and December 31, 2016, respectively,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 estimated costrecovery of environmental investigationinvestments under the Safety, Access, and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agenciesFacility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of the natural gas distribution utilities, with the exception of one site representing $5 million ofto be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the total accrued remediation costs.requested increase in mid-2018.
The finalultimate outcome of these matterspending base rate cases cannot be determined at this time. However,
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the final dispositionsafety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs.
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, 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.
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 being recovered through base rate revenues.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during 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.
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

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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 defendants in a putative class action initially filed 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 mattersentities. 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, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company Gas' financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in 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.
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.
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. The new standard also requires enhanced disclosures 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.
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

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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, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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 other 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 component 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 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 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company Gas' financial statements.

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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 CompanyMerger with Southern Company Gas" herein for additional information.
Southern Company Gas' financial condition remained stable at September 30, 2017. 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 of September 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $752 million. These restrictions 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 for the successor first nine months of 2017, $(342) million for the successor period of July 1, 2016 through September 30, 2016, and $1.1 billion for the predecessor period of January 1, 2016 through June 30, 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.
Net cash used for investing activities totaled $1.2 billion for the successor first nine months of 2017, primarily due 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.
Net cash provided from financing activities totaled $45 million for the successor first nine months of 2017, primarily due to proceeds from debt issuances and capital contributions from Southern Company, partially offset by net repayments of commercial paper borrowings 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, 2016 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.

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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 increase in long-term debt of $603 million 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. Other significant balance sheet changes include an increase of $239 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and decreases of $196 million and $146 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.
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, scheduled 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. 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 Georgia Power, Gulf Power, or Southern Company Gas.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters"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, 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, and other factors. 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 million primarily as a result of $934 million in notes payable. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company 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.

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


At September 30, 2017, Southern Company Gas had approximately $21 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
Company Expires 2022 Unused
  (millions)
Southern Company Gas Capital $1,200
 $1,161
Nicor Gas 700
 700
Total $1,900
 $1,861
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.
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) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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 (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) 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, 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.
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 paper borrowings were as follows:
 Commercial Paper at September 30, 2017 
Commercial Paper 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$836
 1.5% $680
 1.5% $838
Nicor Gas98
 1.3
 40
 1.3
 120
Total$934
 1.5% $720
 1.5%  
(*)Average and maximum amounts are based upon daily balances during the successor three-month period ended September 30, 2017.
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.

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


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 requirements under these contracts at September 30, 2017 were $12 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets, and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
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, the non-principal components totaled $523 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, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.
In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% 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.
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. 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) and (H) 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.

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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 illustrates the change 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 outstanding as of the dates presented.
  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   
  (in millions)  (in millions)
Contracts outstanding at beginning of period,
assets (liabilities), net
 $51
 $(54) $12
 $(54)  $75
Contracts realized or otherwise settled (6) (3) (22) (3)  (77)
Current period changes(a)
 (16) 
 39
 
  (82)
Contracts outstanding at the end of period,
assets (liabilities), net
 29
 (57) 29
 (57)  (84)
Netting of cash collateral 76
 111
 76
 111
  120
Cash collateral and net fair value of contracts
outstanding at end of period
(b)
 $105
 $54
 $105
 $54
  $36
(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 instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $13 million at September 30, 2017 and $7 million at September 30, 2016.
The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2017 were as follows:
   Fair Value Measurements
   Successor – September 30, 2017
 Total
Fair Value
 Maturity
  Year 1  Years 2 & 3 Years 4 and thereafter
 (in millions)
Level 1(a)
$(35) $(10) $(20) $(5)
Level 2(b)
64
 12
 45
 7
Fair value of contracts outstanding at end of period(c)
$29
 $2
 $25
 $2
(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 million at September 30, 2017.

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
B
C
D
E
F
G
H
I
J
K





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


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, 2016 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, 2017 and 2016. 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 CompanyMerger with Southern Company Gas" for additional information regarding a settlement agreement entered into by Mississippi Power 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)

establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.Recently Issued Accounting Standards
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 June 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $7 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at June 30, 2017 and December 31, 2016.
See Note 31 to the financial statements of Mississippi Powerthe registrants under "FERC Matters Fuel Cost Recovery""Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.
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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Market-Based Rate Authority
See Note 3While the registrants expect most of their revenue to be included in the financial statementsscope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority 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" in Item 8 of the Form 10-K for additional information regardingCompany's, the traditional electric operating companies', and Southern Power's market power proceedingCompany 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 amendment to their market-rate tariff.
On May 17, 2017, the FERC accepted the traditional electric operating companies'non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's compliance filing acceptingrevenues includes longer-term PPAs for generation capacity and energy. The registrants expect the termsadoption of ASC 606 will not result in a significant shift from the FERC's February 2, 2017 order regarding an amendment bycurrent 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 PowerCompany Gas expect CIAC to their market-based rate tariff.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 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 FERC's order referencesadoption of ASC 606, including the traditional electric operating companies'cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the registrants' financial statements, the registrants will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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 and Southern Power's market power proceeding, it remains a separate, ongoing matter.Company Gas are evaluating the standard and expect 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

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

Regulatory Matters
Alabama Power2017-07). 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 income statement outside 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. 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, 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 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, the traditional electric operating companies', or Southern Company Gas' financial statements.
See Note 3On 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 adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.
Affiliate Transactions
Prior to the financial statementscompletion of Southern Company andGas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, under "Regulatory Matters Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:
Regulatory ClauseBalance Sheet Line ItemJune 30,
2017
December 31,
2016


(in millions)
Rate CNP Compliance(*)
Deferred under recovered regulatory clause revenues$6
$9
Rate CNP PPAOver recovered regulatory clause revenues1

 Deferred under recovered regulatory clause revenues
142
Retail Energy Cost RecoveryOther regulatory liabilities, current11
76
Natural Disaster ReserveOther regulatory liabilities, deferred56
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 to a deferred regulatory asset account.
Georgia Power, 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 conditions 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.
Rate Plans
See Note 3 to the financial statementsSCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company andGas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power under "Regulatory Matters – Georgiaand Southern Power – Rate Plans"from Southern Company Gas' subsidiaries were approximately $18 million and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of$94 million, respectively. For the Form 10-K for additional information.
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subjectperiod subsequent 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 statementsSouthern Company's acquisition of Southern Company under "Regulatory Matters –Gas through September 30, 2016, natural gas purchases made by Georgia Power – Nuclear Construction" and GeorgiaSouthern 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 offrom Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery"Gas' subsidiaries were approximately $7 million 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$2 million, respectively.

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

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.Goodwill and Other Intangible Assets
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 JuneAt September 30, 2017 Georgia Power's under recovered fuel balance totaled $61 million and is included in 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 andgoodwill was as follows:
 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 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,amortized, but will affect cash flow.
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, thatimpairment test during the termfourth quarter of the Interim Assessment Agreement (i) Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPCeach year, or more frequently if impairment indicators arise.

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

Contractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor)Other intangible assets were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.follows:
The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, 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 July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 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 Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, 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 June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also 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
 At September 30, 2017 At December 31, 2016
 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$288
$(70)$218
 $268
$(32)$236
Trade names159
(15)144
 158
(5)153
Storage and transportation contracts64
(27)37
 64
(2)62
PPA fair value adjustments456
(41)415
 456
(22)434
Other16
(3)13
 11
(1)10
Total other intangible assets subject to amortization$983
$(156)$827

$957
$(62)$895
Other intangible assets not subject to amortization:       
Federal Communications Commission licenses$75
$
$75
 $75
$
$75
Total other intangible assets$1,058
$(156)$902
 $1,032
$(62)$970
        
Southern Power       
Other intangible assets subject to amortization:       
PPA fair value adjustments$456
$(41)$415
 $456
$(22)$434
        
Southern Company Gas       
Other intangible assets subject to amortization:       
Gas marketing services       
Customer relationships$221
$(65)$156
 $221
$(30)$191
Trade names115
(8)107
 115
(2)113
Wholesale gas services       
Storage and transportation contracts64
(27)37
 64
(2)62
Total other intangible assets subject to amortization$400
$(100)$300
 $400
$(34)$366

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

costAmortization associated with other intangible assets was as follows:
 Three Months EndedNine Months Ended
 September 30, 2017
 (in millions)
Southern Company$29
$94
Southern Power$6
$19
Southern Company Gas$20
$66
See Note 12 to the Vogtle Ownersfinancial statements of Southern Company under "Southern Power" and Note 2 to complete constructionthe financial statements of Plant Vogtle Units 3Southern 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) under "Southern CompanyAcquisition of PowerSecure" and " Merger with Southern Company Gas" for additional information.
Property Damage Reserve
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.
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 events 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 of September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 million. See Note (B) under "Regulatory MattersGulf PowerRetail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas had no inventory decrement at September 30, 2017. 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.

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

(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 Georgia Power's financial statements.regulatory matters.
Additionally, on June 9, 2017, Georgia Power, acting for itselfGeneral Litigation Matters
Each registrant is subject to certain claims and as agent forlegal actions arising in the other Vogtle Owners,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 EPC Contractor entered into a services agreement (Services Agreement), which was amendedenvironment, such as regulation of air emissions and restated on July 20, 2017,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 the EPC Contractordamages alleged to transition construction management of Plant Vogtle Units 3have been caused by CO2 and 4other emissions, CCR, and alleged exposure 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.hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of these matterssuch pending or potential litigation against each registrant and any subsidiaries cannot be determinedpredicted at this time.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.
Regulatory MattersSouthern Company
In 2009,On January 20, 2017, a purported 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, PSC votedAtlanta 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 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 certify constructiondismiss 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 Plant Vogtle Units 3Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and 4 withcertain 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' 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 certified capital costshareholder derivative lawsuit in the Superior Court 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 theGwinnett County, State of Georgia enactedand, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the Georgia Nuclear Energy Financing Act, which allows GeorgiaU.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, 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. Asbehalf of June 30, 2017, Georgia Power had recovered approximately $1.4 billion of financing costs.
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 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.Southern Company, unspecified actual damages

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

Underand disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the termslawsuit. 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 consolidated in the U.S. District Court for the Northern District of Georgia and the Vogtle Cost Settlement Agreement,court deferred the Georgia PSCconsolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
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 determine, for retail ratemaking purposes,vigorously defend itself in these matters, the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC on February 27, 2017.
The ultimate outcome of these matterswhich cannot be determined at this time.
Revised Cost and ScheduleGeorgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power andin the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impactSuperior Court of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4.Fulton County, Georgia alleging that Georgia Power's preliminary assessment results indicate that its proportionate sharecollection in rates of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 ranges as follows:
Preliminary in-service dates   
Unit 3February 2021March 2022
Unit 4February 2022March 2023
 (in billions)
Preliminary estimated cost to complete$3.9
$4.6
CWIP as of June 30, 20174.5
 4.5
Guarantee Obligations(1.7) (1.7)
Estimated capital costs$6.7
$7.4
Vogtle Cost Settlement Agreement Revised Forecast(5.7) (5.7)
Estimated net additional capital costs$1.0
$1.7
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion,municipal franchise fees (all of which approximately $1.4 billion had been incurred through June 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate shareare remitted to municipalities) exceeded the amounts allowed in orders of the estimated cancellation costs is approximately $400 million. As a result, as of June 30, 2017, total estimated costs subject to evaluation by Georgia Power and 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 certiorari 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 lien 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 event ofstate 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 cancellation decision are as follows:
 Preliminary Cancellation Cost Estimate
 (in billions)
CWIP as of June 30, 2017$4.5
Financing costs collected, net of tax1.4
Cancellation costs(*)
0.4
Total$6.3
(*)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 existhail 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 eventstate district court in Travis County, Texas alleging breach of cancellation. In addition, under Georgiacontract 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 subsidiaries of 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 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 prudently incurred costs related to certificated projects cancelled byfraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the Georgia PSC are allowed recovery, including carryingclasses they

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

purported to represent, actual and punitive damages, interest, costs, in future retail rates. Georgia Power will continue working withattorney fees, and injunctive relief. On February 8, 2017, the Georgia PSCjudge denied the plaintiffs' motion for class certification 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, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.
Other Matters
As of June 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 ofGas' motion for summary judgment. On March 7, 2017, the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" 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 if 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 if 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.
If construction continues, the risk remains that challenges with 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-K 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.
In 2013, the Florida PSC approvedparties reached a settlement, agreement (2013 Rate Case Settlement Agreement) that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction 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. In the first six months of 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.

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

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. Under 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 consists 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 quarterfinalized and effective on April 3, 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.
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 ItemJune 30,
2017
December 31,
2016


(in millions)
Fuel Cost RecoveryUnder recovered regulatory clause revenues$7
$
Fuel Cost RecoveryOther regulatory liabilities, current
15
Purchased Power Capacity RecoveryUnder recovered regulatory clause revenues5

Environmental Cost RecoveryUnder recovered regulatory clause revenues12
13
Energy Conservation Cost RecoveryUnder recovered regulatory clause revenues2
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.
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.

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

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 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 June 30, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $14 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
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 willsettlement did not have a significant effectmaterial impact on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.financial statements.
Base Rate CasesEnvironmental Matters
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE 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

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

and Integrated System Reinforcement Program, and Integrated Customer Growth Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be 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, 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 increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on 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. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit,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 in annual base rate revenues. The requested increase iswas based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase includesincluded $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 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

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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 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, 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, 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.
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 being recovered through base rate revenues.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during 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.
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

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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 defendants in a putative class action initially filed 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, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company Gas' financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in 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.
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.
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. The new standard also requires enhanced disclosures 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.
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

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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, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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 other 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 component 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 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 2017-12 is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company Gas' financial statements.

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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 CompanyMerger with Southern Company Gas" herein for additional information.
Southern Company Gas' financial condition remained stable at September 30, 2017. 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 of September 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $752 million. These restrictions 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 for the successor first nine months of 2017, $(342) million for the successor period of July 1, 2016 through September 30, 2016, and $1.1 billion for the predecessor period of January 1, 2016 through June 30, 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.
Net cash used for investing activities totaled $1.2 billion for the successor first nine months of 2017, primarily due 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.
Net cash provided from financing activities totaled $45 million for the successor first nine months of 2017, primarily due to proceeds from debt issuances and capital contributions from Southern Company, partially offset by net repayments of commercial paper borrowings 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, 2016 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.

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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 increase in long-term debt of $603 million 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. Other significant balance sheet changes include an increase of $239 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and decreases of $196 million and $146 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.
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, scheduled 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. 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, 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, and other factors. 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 million primarily as a result of $934 million in notes payable. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company 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.

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At September 30, 2017, Southern Company Gas had approximately $21 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:
Company Expires 2022 Unused
  (millions)
Southern Company Gas Capital $1,200
 $1,161
Nicor Gas 700
 700
Total $1,900
 $1,861
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.
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) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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 (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) 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, 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.
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 paper borrowings were as follows:
 Commercial Paper at September 30, 2017 
Commercial Paper 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$836
 1.5% $680
 1.5% $838
Nicor Gas98
 1.3
 40
 1.3
 120
Total$934
 1.5% $720
 1.5%  
(*)Average and maximum amounts are based upon daily balances during the successor three-month period ended September 30, 2017.
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.

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Credit Rating Risk
Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirements under these contracts at September 30, 2017 were $12 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets, and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
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, the non-principal components totaled $523 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, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.
In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% 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.
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. 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) and (H) 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.

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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 illustrates the change 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 outstanding as of the dates presented.
  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   
  (in millions)  (in millions)
Contracts outstanding at beginning of period,
assets (liabilities), net
 $51
 $(54) $12
 $(54)  $75
Contracts realized or otherwise settled (6) (3) (22) (3)  (77)
Current period changes(a)
 (16) 
 39
 
  (82)
Contracts outstanding at the end of period,
assets (liabilities), net
 29
 (57) 29
 (57)  (84)
Netting of cash collateral 76
 111
 76
 111
  120
Cash collateral and net fair value of contracts
outstanding at end of period
(b)
 $105
 $54
 $105
 $54
  $36
(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 instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $13 million at September 30, 2017 and $7 million at September 30, 2016.
The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2017 were as follows:
   Fair Value Measurements
   Successor – September 30, 2017
 Total
Fair Value
 Maturity
  Year 1  Years 2 & 3 Years 4 and thereafter
 (in millions)
Level 1(a)
$(35) $(10) $(20) $(5)
Level 2(b)
64
 12
 45
 7
Fair value of contracts outstanding at end of period(c)
$29
 $2
 $25
 $2
(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 million at September 30, 2017.

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
B
C
D
E
F
G
H
I
J
K





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


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, 2016 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, 2017 and 2016. 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 CompanyMerger 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 Issued 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.
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. The new standard also 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 be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, 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 result 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 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 the registrants' financial statements, the registrants will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value 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 and Southern Company Gas are evaluating the standard and expect 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

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

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 income statement outside 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. 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, 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 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, the traditional electric operating companies', or 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 2017-12 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 adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.
Affiliate Transactions
Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, 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 conditions 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 Power 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.

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

Goodwill and Other Intangible Assets
At September 30, 2017 and December 31, 2016, goodwill was as follows:
 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 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, 2016
 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$288
$(70)$218
 $268
$(32)$236
Trade names159
(15)144
 158
(5)153
Storage and transportation contracts64
(27)37
 64
(2)62
PPA fair value adjustments456
(41)415
 456
(22)434
Other16
(3)13
 11
(1)10
Total other intangible assets subject to amortization$983
$(156)$827

$957
$(62)$895
Other intangible assets not subject to amortization:       
Federal Communications Commission licenses$75
$
$75
 $75
$
$75
Total other intangible assets$1,058
$(156)$902
 $1,032
$(62)$970
        
Southern Power       
Other intangible assets subject to amortization:       
PPA fair value adjustments$456
$(41)$415
 $456
$(22)$434
        
Southern Company Gas       
Other intangible assets subject to amortization:       
Gas marketing services       
Customer relationships$221
$(65)$156
 $221
$(30)$191
Trade names115
(8)107
 115
(2)113
Wholesale gas services       
Storage and transportation contracts64
(27)37
 64
(2)62
Total other intangible assets subject to amortization$400
$(100)$300
 $400
$(34)$366

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

Amortization associated with other intangible assets was as follows:
 Three Months EndedNine Months Ended
 September 30, 2017
 (in millions)
Southern Company$29
$94
Southern Power$6
$19
Southern Company Gas$20
$66
See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) under "Southern CompanyAcquisition of PowerSecure" and " Merger with Southern Company Gas" for additional information.
Property Damage Reserve
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.
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 events 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 of September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 million. See Note (B) under "Regulatory MattersGulf PowerRetail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas had no inventory decrement at September 30, 2017. 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.

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

(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 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 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
On January 20, 2017, a purported 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 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 defendants Southern Company, certain of its directors, 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' 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 behalf of Southern Company, unspecified actual damages

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

and disgorgement of profits and, on its behalf, attorneys' fees 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 consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
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.
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 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 certiorari 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 lien 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 subsidiaries of 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 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

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

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, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.
Environmental Matters
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies 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 projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
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 remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $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 to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.
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

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 Power 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 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 Authority
See Note 3 to the financial statements 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" in Item 8 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 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 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 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.
Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:
Regulatory ClauseBalance Sheet Line 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" in Item 8 of the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" 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-K 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.
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.
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, 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. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism based on amounts approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE 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 be 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, a

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

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 increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on 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 Note (I) under "Southern Company Gas" 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. The requested increase is based on a 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 firstVirginia 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 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. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2018.2017. Rate adjustments are expected to bebased 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 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)
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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 $75$178 million of qualifying assets during the first sixnine months of 2017.
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 liquefied natural gasLNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $94$127 million during the first sixnine months of 2017.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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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.
The recovery of and return on current and future capital investments under Subsequently, the STRIDE program will be included in the annual base rate revenue adjustment under GRAM rather than a separate surcharge. The proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM that was 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 $12$16 million during the first sixnine 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 extension to the SAVE program, under which Virginia Natural Gas invested $14$21 million during the first sixnine months of 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' Safety, Access, and Facility EnhancementSAFE program in 2015. Under the program, Florida City Gas invested $7$9 million during the first sixnine months of 2017.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
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 grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power

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

Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. The remainder of the plant includes the gasifiers and the gas clean-up facilities.
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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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gasifiers on a sustained basis. Most recently, inIn 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 (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 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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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Mississippi Power's Kemper IGCC 2010 project estimate cost estimate attotaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension (which includesin June 2017, the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of June 30, 2017, all of which include 100% of the coststotal cost estimate for the Kemper IGCC are as follows: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 for the Kemper IGCC (Additional DOE Grants).
Cost Category
2010 Project Estimate(a)
 
Cost Estimate
at
Suspension(b)
 
June 30, 2017
Actual Costs
 (in billions)
Plant Subject to Cost Cap(c)(e)
$2.40
 $5.95
 $5.68
Lignite Mine and Equipment0.21
 0.23
 0.23
CO2 Pipeline Facilities
0.14
 0.11
 0.11
AFUDC(d)
0.17
 0.85
 0.85
Combined Cycle and Related Assets Placed in
Service – Incremental
(e)

 0.05
 0.05
General Exceptions0.05
 0.10
 0.08
Deferred Costs(e)

 0.23
 0.23
Additional DOE Grants(f)

 (0.14) (0.14)
Total Kemper IGCC$2.97
 $7.38
 $7.09
(a)
Represents the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.
(b)Represents actual costs through June 30, 2017 and projected costs at the time of project suspension, including estimated post-in-service costs which were expected to be subject to the cost cap.
(c)
The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The Cost Estimate at Suspension and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs2013 MPSC Rate Order" herein for additional information.
(d)
Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs2013 MPSC Rate Order." The Cost Estimate at Suspension also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
(e)Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are included in current rates and are being recognized through income; however, such costs remained in the Cost Estimate at Suspension and are reflected in the Actual Costs at June 30, 2017. The equity return associated with assets placed in service and other non-CWIP accounts deferred for regulatory purposes, as well as the wholesale portion of debt carrying costs, whether deferred or recognized through income, was not included in the Cost Estimate at Suspension or in the Actual Costs at June 30, 2017. At June 30, 2017, such deferred amounts totaled $33 million and $1 million, respectively.
(f)On April 8, 2016, Mississippi Power received approximately $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 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.

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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 Order,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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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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 $3.0 billion$34 million ($21 million after tax) for the secondthird quarter 2017 and $3.1$3.2 billion ($2.2 billion after tax) for the sixnine months ended JuneSeptember 30, 2017.
As of JuneSeptember 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,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 which $1.2 billion is included$80 million in plant in service, $14accumulated depreciation; $15 million in materials and supplies, $22supplies; $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 $95$92 million in other regulatory assets, deferred.
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 Southern Company's and 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 a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket).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. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.
Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.
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 June 30, 2017, approximately $3.3 billion in actualthe time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was relatedsubject to the combined cycleconstruction cost cap, and associated facilitieswas net of the $137 million in Additional DOE Grants.
Mississippi Power reached and $2.8 billion was related tofiled a settlement agreement on August 21, 2017 with certain parties (not including the gasification portionsMississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper IGCC.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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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 Order,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)

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 JuneSeptember 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 SMEPA.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 iswas 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 iswas 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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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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 August 13,December 3, 2015, the Mississippi PSC approvedissued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated withPower and the MPUS regarding the Kemper IGCC assets that arewere commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation (2015 Stipulation) entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPACooperative 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. With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
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 JuneSeptember 30, 2017, the balance associated with these regulatory assets was $117$113 million, of which $22$21 million is included in current assets. See "FERC Matters""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, withfor the first occurring as of May 31, 2016.2016 and 2017 calculations. At JuneSeptember 30, 2017, Mississippi Power's related regulatory liability included in its balance sheet 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

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

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 Costcost 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,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

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

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 $493$494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $459$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.
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 to 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. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (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 in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
In 2010 and as amended in 2012, Mississippi Power and SMEPACooperative Energy (formerly known as SMEPA) entered into an agreement whereby SMEPACooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC (15% Undivided Interest).IGCC. On May 20, 2015, SMEPACooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from SMEPACooperative Energy that were required to be returned to SMEPACooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA.

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

Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.

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, 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 Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Court.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, 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 have 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, 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 results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in these matters, and the ultimate outcome of these matters cannot be determined at this time.
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 by the Mississippi PSC and prohibits the cancellation of 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.
Income Tax Matters
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) under "Section 174 Research and

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

Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.

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

Bonus Depreciation
Approximately $370 million of positive cash flows is expected to result fromAll projected tax benefits previously received for bonus depreciation for the 2017 tax year, but may not all be realized in 2017 duerelated to net operating loss projections for the 2017 tax year, and is dependent upon placing the remainder of the Kemper IGCC were repaid in service by December 31, 2017.connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment any amount previously estimated as bonus depreciationfor income tax purposes, the related deduction would be claimed as a deduction under IRC Section 165. Asin the year of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment.abandonment. See Note (G) 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 research and experimental (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, subject to approval ofwhich was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. 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, and would result in a reversal of the related unrecognized tax benefits, excluding interest. See Note (G) for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.

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

(C)FAIR VALUE MEASUREMENTS
As of JuneSeptember 30, 2017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
Fair Value Measurements Using:  Fair Value Measurements Using:  
As of June 30, 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, 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
(in millions)(in millions)
Southern Company                  
Assets:                  
Energy-related derivatives(a)(b)
$193
 $179
 $
 $
 $372
$231
 $184
 $
 $
 $415
Interest rate derivatives
 11
 
 
 11

 5
 
 
 5
Foreign currency derivatives
 56
 
 
 56

 103
 
 
 103
Nuclear decommissioning trusts(c)
728
 966
 
 25
 1,719
752
 1,004
 
 26
 1,782
Cash equivalents834
 
 
 
 834
1,271
 
 
 
 1,271
Other investments9
 
 1
 
 10
9
 
 1
 
 10
Total$1,764
 $1,212
 $1
 $25
 $3,002
$2,263
 $1,296
 $1
 $26
 $3,586
Liabilities:                  
Energy-related derivatives(a)(b)
$205
 $161
 $
 $
 $366
$265
 $146
 $
 $
 $411
Interest rate derivatives
 23
 
 
 23

 24
 
 
 24
Foreign currency derivatives
 23
 
 
 23

 23
 
 
 23
Contingent consideration
 
 20
 
 20

 
 20
 
 20
Total$205
 $207
 $20
 $
 $432
$265
 $193
 $20
 $
 $478
                  
Alabama Power                  
Assets:                  
Energy-related derivatives$
 $9
 $
 $
 $9
$
 $9
 $
 $
 $9
Nuclear decommissioning trusts:(d)
        

        

Domestic equity411
 79
 
 
 490
422
 81
 
 
 503
Foreign equity56
 54
 
 
 110
60
 57
 
 
 117
U.S. Treasury and government agency securities
 29
 
 
 29

 27
 
 
 27
Corporate bonds22
 145
 
 
 167
19
 150
 
 
 169
Mortgage and asset backed securities
 18
 
 
 18

 18
 
 
 18
Private Equity
 
 
 25
 25

 
 
 26
 26
Other
 6
 
 
 6

 8
 
 
 8
Cash equivalents493
 
 
 
 493
808
 
 
 
 808
Total$982
 $340
 $
 $25
 $1,347
$1,309
 $350
 $
 $26
 $1,685
Liabilities:                  
Energy-related derivatives$
 $11
 $
 $
 $11
$
 $7
 $
 $
 $7

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

Fair Value Measurements Using:  Fair Value Measurements Using:  
As of June 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, 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
(in millions)(in millions)
Georgia Power                  
Assets:                  
Energy-related derivatives$
 $15
 $
 $
 $15
$
 $18
 $
 $
 $18
Interest rate derivatives
 1
 
 
 1

 1
 
 
 1
Nuclear decommissioning trusts:(d) (e)
                  
Domestic equity225
 1
 
 
 226
235
 1
 
 
 236
Foreign equity
 147
 
 
 147

 156
 
 
 156
U.S. Treasury and government agency securities
 198
 
 
 198

 225
 
 
 225
Municipal bonds
 72
 
 
 72

 64
 
 
 64
Corporate bonds
 169
 
 
 169

 160
 
 
 160
Mortgage and asset backed securities
 41
 
 
 41

 38
 
 
 38
Other14
 7
 
 
 21
16
 19
 
 
 35
Cash equivalents50
 
 
 
 50
112
 
 
 
 112
Total$289
 $651
 $
 $
 $940
$363
 $682
 $
 $
 $1,045
Liabilities:                  
Energy-related derivatives$
 $14
 $
 $
 $14
$
 $11
 $
 $
 $11
Interest rate derivatives
 3
 
 
 3

 3
 
 
 3
Total$
 $17
 $
 $
 $17
$
 $14
 $
 $
 $14
                  
Gulf Power                  
Assets:                  
Energy-related derivatives$
 $1
 $
 $
 $1
Cash equivalents21
 
 
 
 21
$21
 $
 $
 $
 $21
Total$21
 $1
 $
 $
 $22
Liabilities:                  
Energy-related derivatives$
 $29
 $
 $
 $29
$
 $22
 $
 $
 $22
                  
Mississippi Power                  
Assets:                  
Energy-related derivatives$
 $2
 $
 $
 $2
$
 $3
 $
 $
 $3
Interest rate derivatives
 3
 
 
 3

 2
 
 
 2
Cash equivalents100
 
 
 
 100
209
 
 
 
 209
Total$100
 $5
 $
 $
 $105
$209
 $5
 $
 $
 $214
Liabilities:                  
Energy-related derivatives$
 $10
 $
 $
 $10
$
 $7
 $
 $
 $7
                  

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

Fair Value Measurements Using:  Fair Value Measurements Using:  
As of June 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, 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
(in millions)(in millions)
Southern Power                  
Assets:                  
Energy-related derivatives$
 $14
 $
 $
 $14
$
 $9
 $
 $
 $9
Foreign currency derivatives
 56
 
 
 56

 103
 
 
 103
Cash equivalents90
 
 
 
 90
Total$
 $70
 $
 $
 $70
$90
 $112
 $
 $
 $202
Liabilities:                  
Energy-related derivatives$
 $9
 $
 $
 $9
$
 $4
 $
 $
 $4
Foreign currency derivatives
 23
 
 
 23

 23
 
 
 23
Contingent consideration
 
 20
 
 20

 
 20
 
 20
Total$

$32

$20

$

$52
$

$27

$20

$

$47
                  
Southern Company Gas                  
Assets:                  
Energy-related derivatives(a)(b)
$193
 $138
 $
 $
 $331
$231
 $145
 $
 $
 $376
Liabilities:                  
Energy-related derivatives(a)(b)
$205
 $86
 $
 $
 $291
$265
 $95
 $
 $
 $360
(a)Excludes $11$13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)Excludes cash collateral of $71$76 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 JuneSeptember 30, 2017, approximately $38$66 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $55$50 million and $118$168 million, respectively, for the three and sixnine months ended JuneSeptember 30, 2017, and by $47$49 million and $67$116 million, respectively, for the three and sixnine months ended JuneSeptember 30, 2016. Alabama Power recorded an increaseincreases in fair value of $28$25 million and $62 million, respectively, for the three and six months ended June 30, 2017 and $29 million and $40$87 million, respectively, for the three and sixnine months ended JuneSeptember 30, 2017 and $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 as a change in regulatory liabilities related to its AROs. Georgia Power recorded increases in fair value of $27$25 million and $56$81 million, respectively, for the three and sixnine months ended JuneSeptember 30, 2017 and $18$23 million and $27$50 million, respectively, for the three and sixnine months ended JuneSeptember 30, 2016 as a change in its regulatory asset related to its AROs.
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from

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

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

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) for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to make generation-based payments to the seller over a period ranging from 10 to 30 years, beginning at the commercial operation date. 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. 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 JuneSeptember 30, 2017, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
As of June 30, 2017:
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
As of September 30, 2017:
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
(in millions) (in millions) 
Southern Company$25
 $22
 Not Applicable Not Applicable$26
 $24
 Not Applicable Not Applicable
Alabama Power$25
 $22
 Not Applicable Not Applicable$26
 $24
 Not Applicable Not Applicable
Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.

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

As of JuneSeptember 30, 2017, 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$46,631
 $48,228
$47,269
 $49,348
Alabama Power$7,440
 $8,041
$7,404
 $8,031
Georgia Power$10,888
 $11,585
$11,713
 $12,237
Gulf Power$1,292
 $1,336
$1,292
 $1,352
Mississippi Power$2,125
 $2,071
$2,123
 $2,117
Southern Power$5,725
 $5,878
$5,810
 $5,916
Southern Company Gas$5,699
 $6,031
$5,862
 $6,230
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.
(D)STOCKHOLDERS' EQUITY
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
Three Months Ended June 30, 2017Three Months Ended June 30, 2016Six Months Ended June 30, 2017Six Months Ended June 30, 2016Three Months Ended September 30, 2017Three Months Ended September 30, 2016Nine Months Ended September 30, 2017Nine Months Ended September 30, 2016
(in millions)(in millions)
As reported shares998
934
996
925
1,003
968
998
940
Effect of options and performance share award units7
6
7
6
7
7
7
5
Diluted shares1,005
940
1,003
931
1,010
975
1,005
945
Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three and sixnine months ended JuneSeptember 30, 2017 and 2016.

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(*)
(in thousands) (in millions)(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 (loss) attributable to Southern Company

 (723)

(723)
Consolidated net income attributable to Southern Company

 347


347
Other comprehensive income (loss)

 (11)

(11)

 (2)

(2)
Stock issued9,129

 417


417
13,308

 613


613
Stock-based compensation

 72


72


 97


97
Cash dividends on common stock

 (1,134)

(1,134)

 (1,716)

(1,716)
Preference stock redemption

 
(150)
(150)

 
(150)
(150)
Contributions from noncontrolling interests

 


71
71


 

77
77
Distributions to noncontrolling interests

 

(40)(40)

 

(87)(87)
Net income attributable to noncontrolling interests

 

16
16


 

45
45
Reclassification from redeemable noncontrolling interests

 

114
114


 

114
114
Other
(49) (7)3
1
(3)
(75) (15)3
1
(11)
Balance at June 30, 20171,000,342
(868) $23,372
$462
$1,407
$25,241
Balance at September 30, 20171,004,521
(894) $24,082
$462
$1,395
$25,939
      
Balance at December 31, 2015915,073
(3,352) $20,592
$609
$781
$21,982
915,073
(3,352) $20,592
$609
$781
$21,982
Consolidated net income attributable to Southern Company

 1,112


1,112


 2,251


2,251
Other comprehensive income (loss)

 (117)

(117)

 (95)

(95)
Stock issued27,297
2,599
 1,383


1,383
65,725
2,599
 3,265


3,265
Stock-based compensation

 67


67


 94


94
Cash dividends on common stock

 (1,023)

(1,023)

 (1,553)

(1,553)
Contributions from noncontrolling interests

 

169
169


 

357
357
Distributions to noncontrolling interests

 

(10)(10)

 

(21)(21)
Purchase of membership interests from noncontrolling interests

 

(129)(129)

 

(129)(129)
Net income attributable to noncontrolling interests

 

11
11


 

36
36
Other
(19) 1


1

(46) (7)

(7)
Balance at June 30, 2016942,370
(772) $22,015
$609
$822
$23,446
Balance at September 30, 2016980,798
(799) $24,547
$609
$1,024
$26,180
(*)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.

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

(E)FINANCING
Going Concern
As of JuneSeptember 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $930$769 million primarily due to approximately $935 million that will be required through JuneSeptember 30, 2018 to fund maturities of long-term debt and $17$4 million that will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate 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 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 (B) under "Integrated Coal Gasification Combined Cycle."
DOE Loan Guarantee Borrowings
See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information regarding Georgia Power's loan guarantee agreement (LoanLoan Guarantee Agreement)Agreement with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.
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 Services Agreement and the related intellectual property licenses (IP Licenses). The purpose of the amendment is to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments being prepared as a result of the bankruptcy of the EPC Contractor (Cost Assessments).
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 has (i) completed the Cost Assessmentscost-to-complete and cancellation cost assessments prepared as a result of the bankruptcy 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 DOE (together with the Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Upon satisfaction of the conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under 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 advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations 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

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

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)

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 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 Services Agreement or rejection of the 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) 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 circumstances Georgia Power may be required to make additional prepayments in connection with its receipt of payments 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 MattersGeorgia PowerNuclear 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 JuneSeptember 30, 2017 was approximately $1.6$1.5 billion (comprised of approximately $890$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 JuneSeptember 30, 2017, the traditional electric operating companies had approximately $626$699 million (comprised of approximately $436$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 reofferedremarketed 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 JuneSeptember 30, 2017:
Expires   
Executable Term
Loans
 
Expires Within
One Year
Expires   
Executable Term
Loans
 
Expires Within
One Year
Company20172018201920202022 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
20172018201920202022 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)(in millions)
Southern Company(a)
$
$
$
$
$2,000
 $2,000
 $2,000
 $
 $
 $
 $
$
$
$
$
$2,000
 $2,000
 $2,000
 $
 $
 $
 $
Alabama Power3
532


800
 1,335
 1,335
 
 
 
 35

35

500
800
 1,335
 1,335
 
 
 
 35
Georgia Power



1,750
 1,750
 1,732
 
 
 
 




1,750
 1,750
 1,732
 
 
 
 
Gulf Power30
195
25
30

 280
 280
 45
 
 
 40
30
195
25
30

 280
 280
 45
 
 
 40
Mississippi Power113




 113
 100
 
 13
 13
 100
100




 100
 100
 
 
 
 100
Southern Power Company(b)



750
 750
 675
 
 
 
 




750
 750
 728
 
 
 
 
Southern Company Gas(b)(c)




1,900
 1,900
 1,849
 
 
 
 




1,900
 1,900
 1,861
 
 
 
 
Other10
30



 40
 40
 20
 
 20
 20

30



 30
 30
 20
 
 20
 10
Southern Company Consolidated$156
$757
$25
$30
$7,200
 $8,168
 $8,011
 $65
 $13
 $33
 $195
$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 sixnine months of 2017:
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 and Redemptions
 
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
 $
 $
 $500
 $400
$300
 $400
 $
 $500
 $400
Alabama Power550
 200
 
 
 
550
 200
 36
 
 
Georgia Power850
 450
 27
 
 3
1,350
 450
 65
 370
 13
Gulf Power300
 85
 
 6
 
300
 85
 
 6
 
Mississippi Power
 
 
 40
 893

 
 
 40
 893
Southern Power
 
 
 3
 3

 
 
 43
 4
Southern Company Gas(c)
450
 
 
 
 
450
 
 
 200
 22
Other
 
 
 
 8

 
 
 
 12
Elimination(d)

 
 
 (40) (591)
 
 
 (40) (599)
Southern Company Consolidated$2,450
 $735
 $27
 $509
 $716
$2,950
 $1,135
 $101
 $1,119
 $745
(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)IntercompanyIncludes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.
Southern Company
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness2057 and for other general corporate purposes.
Also in June 2017, Southern Company issued $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 used to repay short-term indebtedness and for other general corporate purposes.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.
Alabama Power
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
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

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, Georgia Power issued $450 million aggregate principal amount of 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.

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

In April 2017, Georgia Power purchased and held $27 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 may reofferremarketed these bonds to the public at a later date.public.
In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, which mature onwith maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, andwhich 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 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.
Gulf Power
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.
In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 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 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,

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, 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) 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, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.
In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% 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.
(F)RETIREMENT BENEFITS
Southern Company has a 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 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 pension plan are anticipated for the year ending December 31, 2017. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric

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.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas in Item 8 of the Form 10-K for additional information.

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

Components of the net periodic benefit costs for the three and sixnine months ended JuneSeptember 30, 2017 and 2016 are presented in the following tables.
Pension Plans
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
(in millions)(in millions)
Three Months Ended June 30, 2017         
Three Months Ended September 30, 2017         
Service cost$74
 $16
 $18
 $4
 $3
$73
 $15
 $19
 $3
 $4
Interest cost113
 24
 35
 5
 5
114
 25
 34
 5
 5
Expected return on plan assets(225) (49) (70) (9) (10)(224) (49) (71) (10) (9)
Amortization:                  
Prior service costs3
 
 1
 
 1
3
 1
 
 
 
Net (gain)/loss41
 11
 14
 1
 2
41
 10
 15
 2
 1
Net periodic pension cost (income)$6
 $2
 $(2) $1
 $1
$7
 $2
 $(3) $
 $1
Six Months Ended June 30, 2017         
Nine Months Ended September 30, 2017         
Service cost$147
 $32
 $37
 $7
 $7
$220
 $47
 $56
 $10
 $11
Interest cost227
 48
 69
 10
 10
341
 73
 103
 15
 15
Expected return on plan assets(449) (98) (141) (19) (20)(673) (147) (212) (29) (29)
Amortization:                  
Prior service costs6
 1
 2
 
 1
9
 2
 2
 
 1
Net (gain)/loss81
 21
 28
 3
 4
122
 31
 43
 5
 5
Net periodic pension cost (income)$12
 $4
 $(5) $1
 $2
$19
 $6
 $(8) $1
 $3
Three Months Ended June 30, 2016         
Three Months Ended September 30, 2016         
Service cost$62
 $15
 $18
 $3
 $3
$68
 $14
 $17
 $3
 $3
Interest cost101
 24
 34
 4
 5
110
 23
 34
 5
 4
Expected return on plan assets(187) (46) (65) (8) (8)(203) (46) (64) (9) (9)
Amortization:                  
Prior service costs3
 
 2
 1
 
3
 1
 1
 
 1
Net (gain)/loss37
 10
 13
 1
 1
45
 10
 14
 2
 2
Net periodic pension cost$16
 $3
 $2
 $1
 $1
$23
 $2
 $2
 $1
 $1
Six Months Ended June 30, 2016         
Nine Months Ended September 30, 2016         
Service cost$124
 $29
 $35
 $6
 $6
$192
 $43
 $52
 $9
 $9
Interest cost201
 48
 68
 9
 10
311
 71
 102
 14
 14
Expected return on plan assets(374) (92) (129) (17) (17)(577) (138) (193) (26) (26)
Amortization:                  
Prior service costs7
 1
 3
 1
 
10
 2
 4
 1
 1
Net (gain)/loss75
 20
 27
 3
 3
120
 30
 41
 5
 5
Net periodic pension cost$33
 $6
 $4
 $2
 $2
$56
 $8
 $6
 $3
 $3

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

Pension Plans
Southern
Company
Gas
Southern
Company
Gas
(in millions)(in millions)
Successor – Three Months Ended June 30, 2017 
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$5
$17
Interest cost10
30
Expected return on plan assets(17)(53)
Amortization:  
Prior service costs(1)(1)
Net (gain)/loss5
15
Net periodic pension cost$2
$8
Successor – Six Months Ended June 30, 2017 
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 
Service cost$11
$13
Interest cost20
21
Expected return on plan assets(35)(33)
Amortization:  
Prior service costs(1)(1)
Net (gain)/loss10
13
Net periodic pension cost$5
$13
 
 
Predecessor – Three Months Ended June 30, 2016 
Service cost$7
Interest cost11
Expected return on plan assets(17)
Amortization: 
Prior service costs(1)
Net (gain)/loss7
Net periodic pension cost$7
Predecessor – Six Months Ended June 30, 2016 
Service cost$13
Interest cost21
Expected return on plan assets(33)
Amortization: 
Prior service costs(1)
Net (gain)/loss13
Net periodic pension cost$13

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

Postretirement Benefits
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
(in millions)(in millions)
Three Months Ended June 30, 2017         
Three Months Ended September 30, 2017         
Service cost$6
 $2
 $1
 $1
 $1
$6
 $1
 $2
 $
 $
Interest cost20
 4
 8
 
 1
19
 4
 6
 1
 1
Expected return on plan assets(17) (8) (6) (1) (1)(16) (5) (6) 
 
Amortization:                  
Prior service costs1
 1
 1
 
 
2
 1
 
 
 
Net (gain)/loss5
 1
 1
 
 
3
 
 3
 
 
Net periodic postretirement benefit cost$15
 $
 $5
 $
 $1
$14
 $1
 $5
 $1
 $1
Six Months Ended June 30, 2017         
Nine Months Ended September 30, 2017         
Service cost$12
 $3
 $3
 $1
 $1
$18
 $4
 $5
 $1
 $1
Interest cost40
 9
 15
 1
 2
59
 13
 21
 2
 3
Expected return on plan assets(33) (14) (12) (1) (1)(49) (19) (18) (1) (1)
Amortization:                  
Prior service costs3
 2
 1
 
 
5
 3
 1
 
 
Net (gain)/loss7
 1
 3
 
 
10
 1
 6
 
 
Net periodic postretirement benefit cost$29
 $1
 $10
 $1
 $2
$43
 $2
 $15
 $2
 $3
Three Months Ended June 30, 2016         
Three Months Ended September 30, 2016         
Service cost$6
 $2
 $1
 $1
 $1
$6
 $1
 $2
 $
 $
Interest cost17
 4
 7
 
 1
20
 5
 7
 1
 
Expected return on plan assets(14) (7) (5) (1) (1)(16) (6) (6) 
 
Amortization:                  
Prior service costs1
 1
 1
 
 
1
 1
 
 
 
Net (gain)/loss4
 1
 2
 
 
5
 
 3
 
 1
Net periodic postretirement benefit cost$14
 $1
 $6
 $
 $1
$16
 $1
 $6
 $1
 $1
Six Months Ended June 30, 2016         
Nine Months Ended September 30, 2016         
Service cost$11
 $3
 $3
 $1
 $1
$17
 $4
 $5
 $1
 $1
Interest cost35
 9
 15
 1
 2
55
 14
 22
 2
 2
Expected return on plan assets(28) (13) (11) (1) (1)(44) (19) (17) (1) (1)
Amortization:                  
Prior service costs3
 2
 1
 
 
4
 3
 1
 
 
Net (gain)/loss7
 1
 4
 
 
12
 1
 7
 
 1
Net periodic postretirement benefit cost$28
 $2
 $12
 $1
 $2
$44
 $3
 $18
 $2
 $3

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

Postretirement Benefits
Southern
Company
Gas
Southern
Company
Gas
(in millions)(in millions)
Successor – Three Months Ended June 30, 2017 
Successor – Three Months Ended September 30, 2017 
Service cost$
$1
Interest cost2
3
Expected return on plan assets(1)(2)
Amortization:  
Prior service costs
(1)
Net (gain)/loss1
1
Net periodic postretirement benefit cost$2
$2
Successor – Six Months Ended June 30, 2017 
Successor – Nine Months Ended September 30, 2017 
Service cost$1
$2
Interest cost5
8
Expected return on plan assets(3)(5)
Amortization:  
Prior service costs(1)(2)
Net (gain)/loss2
3
Net periodic postretirement benefit cost$4
$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 – Three Months Ended June 30, 2016 
Predecessor – January 1, 2016 through June 30, 2016 
Service cost$
$1
Interest cost2
5
Expected return on plan assets(1)(3)
Amortization:  
Prior service costs
(1)
Net (gain)/loss1
2
Net periodic postretirement benefit cost$2
$4
Predecessor – Six Months Ended 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

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

(G)INCOME TAXES
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.9 billion as of JuneSeptember 30, 2017 compared to $1.8 billion as of December 31, 2016.
The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The expected utilization of tax credit carryforwards could be further delayed by numerous factors. These factors include the acquisition of additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss, and potential tax reform legislation, as well as additional deductions in the event of an asset abandonment. The ultimate outcome of these matters cannot be determined at this time.
Valuation Allowances
At JuneSeptember 30, 2017, valuation allowances were as follows:
Mississippi Power 
Southern Company
Gas
 Southern CompanyMississippi Power 
Southern Company
Gas
 Southern Company
(in millions)(in millions)
Federal$
 $18
 $18
$
 $18
 $18
State (net of federal benefit)46
 1
 63
46
 1
 64
Balance at June 30, 2017$46
 $19
 $81
Balance at September 30, 2017$46
 $19
 $82
Southern Company had valuation allowances, net of the federal benefit, of $81$82 million at JuneSeptember 30, 2017 compared to $21 million at December 31, 2016. The increase was primarily due to Mississippi Power's projected inability to utilize the State of Mississippi net operating loss.
Effective Tax Rate
Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs.
Southern Company's effective tax (benefit) rate was (28.6)%42.6% for the sixnine months ended JuneSeptember 30, 2017 compared to 29.4%28.3% for the corresponding period in 2016. The effective tax rate decreaseincrease was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include a decrease in tax benefits from solar ITCs and an increase in state valuation allowances, partially offset by an increase in tax benefits from wind PTCs and state apportionment rate changes, partially offset by a decrease in tax benefits from ITCs and an increase in state valuation allowances.PTCs.
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.


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

Mississippi Power
Mississippi Power's effective tax (benefit) rate was (30.5)(30.3)% for the sixnine months ended JuneSeptember 30, 2017 compared to (208.1)(282.8)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated

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

probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.
Southern Power
Southern Power's effective tax (benefit) rate was (114.7)(66.5)% for the sixnine months ended JuneSeptember 30, 2017 compared to (74.0)(88.9)% for the corresponding period in 2016. The effective tax rate decreaseincrease was primarily due to additional PTCs arising from Southern Power's wind facility acquisitions, state apportionment rate changes, and lower pre-tax earnings, partially offset by a decrease in tax benefits from ITCs.solar ITCs, partially offset by additional wind PTCs and state apportionment rate changes.
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.
During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate 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 result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and 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 periods 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.
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 sixnine months ended JuneSeptember 30, 2017 for unrecognized tax benefits were as follows:
Mississippi Power Southern Power Southern CompanyMississippi Power Southern Power Southern Company
(in millions)(in millions)
Unrecognized tax benefits as of December 31, 2016$465
 $17
 $484
$465
 $17
 $484
Tax positions from current periods3
 1
 10
2
 
 9
Tax positions from prior periods
 1
 7
(175) (17) (186)
Balance as of June 30, 2017$468
 $19
 $501
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 will bewere impacted as a result of the proposed settlement of R&E expenditures associated with the Kemper IGCC.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 June 30, 2017 As of December 31, 2016As of September 30, 2017 As of December 31, 2016
Mississippi Power Southern Power Southern Company Southern CompanyMississippi Power Southern Company Southern Company
(in millions)(in millions)
Tax positions impacting the effective tax rate$4
 $19
 $37
 $20
$2
 $17
 $20
Tax positions not impacting the effective tax rate464
 
 464
 464

 
 464
Balance of unrecognized tax benefits$468
 $19
 $501
 $484
$2
 $17
 $484
The tax positions impacting the effective tax rate primarily relate to federal deferred income tax credits and Southern Company's estimate of the uncertainty related to the amount of those benefits, and state tax benefits and charitable contribution carryforwards that will bewere impacted as a result of the proposed settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. If these tax positions are not able to be recognized due to a federal audit adjustment in

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

the amount that has been estimated, the amount of tax credit carryforwards discussed above would be reduced by approximately $98 million.
Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See "Section 174 Research and Experimental Deduction" herein for more information.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. In addition,However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax return isreturns 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.
The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures under IRC Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval ofwhich was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. Due toAs a result of the uncertainty related to this tax position,JCT approval, Southern Company and Mississippi Power hadrecognized $176 million of previously unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million and associated interest ofreversed $36 million as of June 30, 2017.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 and would result in a reversal of the related unrecognized tax benefits, excluding interest.year an abandonment is determined. The ultimate outcome of this matter cannot be determined at this time.
(H)DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the

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) 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

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

impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively.
Energy-Related Derivatives
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 the moratorium on Gulf Power's fuel-hedging program throughuntil 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. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.
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 as the hedged transactions are reflected in earnings.
Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric 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.

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

At JuneSeptember 30, 2017, 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(*)
472 2021 2024463 2021 2024
Alabama Power70 2020 66 2020 
Georgia Power160 2020 159 2021 
Gulf Power35 2020 28 2020 
Mississippi Power41 2021 44 2021 
Southern Power25 2017 13 2018 
Southern Company Gas(*)
141 2019 2024153 2020 2024
(*)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 3.53.3 billion mmBtu and short natural gas positions of 3.43.1 billion mmBtu as of JuneSeptember 30, 2017, 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 3134 million mmBtu for Southern Company, 1011 million mmbtu for Georgia Power and Southern Power, 5 million mmbtu for Alabama Power, and 3 million mmBtu for Gulf Power, and 4 million mmBtu for Mississippi 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 JuneSeptember 30, 2018 are $6$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 ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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

At JuneSeptember 30, 2017, the following interest rate derivatives were outstanding:
Notional
Amount
 
Interest
Rate
Received
Weighted
Average
Interest
Rate Paid
Hedge
Maturity
Date
 Fair Value
Gain (Loss) at June 30, 2017
Notional
Amount
 
Interest
Rate
Received
Weighted
Average
Interest
Rate Paid
Hedge
Maturity
Date
 Fair Value Gain (Loss) at September 30, 2017
(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  
Mississippi Power$900
 1-month
LIBOR 
0.79%March 2018 $3
$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(*)
250
 1.30%3-month
LIBOR + 0.17%
August 2017 
300
 2.75%3-month
LIBOR + 0.92%
June 2020 
Southern Company(*)
300
 2.75%3-month
LIBOR + 0.92%
June 2020 1
1,500
 2.35%1-month
LIBOR + 0.87%
July 2021 (19)
Southern Company(*)
1,500
 2.35%1-month
LIBOR + 0.87%
July 2021 (14)
Georgia Power250
 5.40%3-month
LIBOR + 4.02%
June 2018 
250
 5.40%3-month
LIBOR + 4.02%
June 2018 
Georgia Power500
 1.95%3-month
LIBOR + 0.76%
December 2018 (2)500
 1.95%3-month
LIBOR + 0.76%
December 2018 (2)
Georgia Power200
 4.25%3-month
LIBOR + 2.46%
December 2019 1
200
 4.25%3-month
LIBOR + 2.46%
December 2019 
Southern Company Consolidated$3,900
 $(11)$3,650
 $(19)
(*)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 JuneSeptember 30, 2018 are $(21)$(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 is recorded in OCI and is reclassified into earnings at the same time that 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 JuneSeptember 30, 2017, the following foreign currency derivatives were outstanding:

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

(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$18
$677
2.95%600
1.00%June 2022$42
Southern Power564
3.78%500
1.85%June 202615
564
3.78%500
1.85%June 202638
Total$1,241
 1,100
 $33
$1,241
 1,100
 $80
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 JuneSeptember 30, 2018 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 June 30, 2017As of December 31, 2016As of September 30, 2017As of December 31, 2016
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/Liabilities from risk management activities, net of collateral$23
$35
$73
$27
Other current assets/Other current liabilities$21
$25
$73
$27
Other deferred charges and assets/Other deferred credits and liabilities8
31
25
33
13
23
25
33
Total derivatives designated as hedging instruments for regulatory purposes$31
$66
$98
$60
$34
$48
$98
$60
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Energy-related derivatives:  
Other current assets/Liabilities from risk management activities, net of collateral$13
$10
$23
$7
Other current assets/Other current liabilities$8
$6
$23
$7
Interest rate derivatives:  
Other current assets/Liabilities from risk management activities, net of collateral11
1
12
1
Other current assets/Other current liabilities5
1
12
1
Other deferred charges and assets/Other deferred credits and liabilities
22
1
28

23
1
28
Foreign currency derivatives:  
Other current assets/Liabilities from risk management activities, net of collateral
23

25
Other current assets/Other current liabilities
23

25
Other deferred charges and assets/Other deferred credits and liabilities56


33
103


33
Total derivatives designated as hedging instruments in cash flow and fair value hedges$80
$56
$36
$94
$116
$53
$36
$94
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Other current assets/Liabilities from risk management activities, net of collateral$237
$202
$489
$483
Other current assets/Other current liabilities$271
$254
$489
$483
Other deferred charges and assets/Other deferred credits and liabilities102
86
66
81
115
103
66
81
Interest rate derivatives:  
Other current assets/Liabilities from risk management activities, net of collateral

1

Other current assets/Other current liabilities

1

Total derivatives not designated as hedging instruments$339
$288
$556
$564
$386
$357
$556
$564
Gross amounts recognized$450
$410
$690
$718
$536
$458
$690
$718
Gross amounts offset(*)
$(219)$(290)$(462)$(524)$(275)$(351)$(462)$(524)
Net amounts recognized in the Balance Sheets$231
$120
$228
$194
$261
$107
$228
$194

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

As of June 30, 2017As of December 31, 2016As of September 30, 2017As of December 31, 2016
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/Liabilities from risk management activities$7
$7
$13
$5
Other current assets/Other current liabilities$6
$4
$13
$5
Other deferred charges and assets/Other deferred credits and liabilities2
4
7
4
3
3
7
4
Total derivatives designated as hedging instruments for regulatory purposes$9
$11
$20
$9
$9
$7
$20
$9
Gross amounts recognized$9
$11
$20
$9
$9
$7
$20
$9
Gross amounts offset$(6)$(6)$(8)$(8)$(5)$(5)$(8)$(8)
Net amounts recognized in the Balance Sheets$3
$5
$12
$1
$4
$2
$12
$1
  
Georgia Power  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Other current liabilities$10
$4
$30
$1
$10
$3
$30
$1
Other deferred charges and assets/Other deferred credits and liabilities5
10
14
7
8
8
14
7
Total derivatives designated as hedging instruments for regulatory purposes$15
$14
$44
$8
$18
$11
$44
$8
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Interest rate derivatives:  
Other current assets/Other current liabilities$1
$1
$2
$
$1
$1
$2
$
Other deferred charges and assets/Other deferred credits and liabilities
2

3

2

3
Total derivatives designated as hedging instruments in cash flow and fair value hedges$1
$3
$2
$3
$1
$3
$2
$3
Gross amounts recognized$16
$17
$46
$11
$19
$14
$46
$11
Gross amounts offset$(9)$(9)$(8)$(8)$(10)$(10)$(8)$(8)
Net amounts recognized in the Balance Sheets$7
$8
$38
$3
$9
$4
$38
$3
  
Gulf Power  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Liabilities from risk management activities$1
$16
$4
$12
Other current assets/Other current liabilities$
$13
$4
$12
Other deferred charges and assets/Other deferred credits and liabilities
13
1
17

9
1
17
Total derivatives designated as hedging instruments for regulatory purposes$1
$29
$5
$29
$
$22
$5
$29
Gross amounts recognized$1
$29
$5
$29
$
$22
$5
$29
Gross amounts offset$(1)$(1)$(4)$(4)$
$
$(4)$(4)
Net amounts recognized in the Balance Sheets$
$28
$1
$25
$
$22
$1
$25

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

As of June 30, 2017As of December 31, 2016As of September 30, 2017As of December 31, 2016
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
$6
$2
$6
$1
$4
$2
$6
Other deferred charges and assets/Other deferred credits and liabilities1
4
2
5
2
3
2
5
Total derivatives designated as hedging instruments for regulatory purposes$2
$10
$4
$11
$3
$7
$4
$11
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Interest rate derivatives:  
Other current assets/Other current liabilities$3
$
$2
$
$2
$
$2
$
Other deferred charges and assets/Other deferred credits and liabilities

1



1

Total derivatives designated as hedging instruments in cash flow and fair value hedges$3
$
$3
$
$2
$
$3
$
Gross amounts recognized$5
$10
$7
$11
$5
$7
$7
$11
Gross amounts offset$(2)$(2)$(3)$(3)$(3)$(3)$(3)$(3)
Net amounts recognized in the Balance Sheets$3
$8
$4
$8
$2
$4
$4
$8
  
Southern Power  
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Energy-related derivatives:  
Other current assets/Other current liabilities$13
$8
$18
$4
$8
$4
$18
$4
Foreign currency derivatives:  
Other current assets/Other current liabilities
23

25

23

25
Other deferred charges and assets/Other deferred credits and liabilities56


33
103


33
Total derivatives designated as hedging instruments in cash flow and fair value hedges$69
$31
$18
$62
$111
$27
$18
$62
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Other current assets/Other current liabilities$1
$1
$3
$1
$1
$
$3
$1
Interest rate derivatives:  
Other current assets/Other current liabilities

1



1

Total derivatives not designated as hedging instruments$1
$1
$4
$1
$1
$
$4
$1
Gross amounts recognized$70
$32
$22
$63
$112
$27
$22
$63
Gross amounts offset$(2)$(2)$(5)$(5)$(1)$(1)$(5)$(5)
Net amounts recognized in the Balance Sheets$68
$30
$17
$58
$111
$26
$17
$58

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

As of June 30, 2017As of December 31, 2016As of September 30, 2017As of December 31, 2016
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
$2
$24
$3
$4
$1
$24
$3
Other deferred charges and assets/Other deferred credits and liabilities

1



1

Total derivatives designated as hedging instruments for regulatory purposes$4
$2
$25
$3
$4
$1
$25
$3
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Energy-related derivatives:  
Assets from risk management activities/Liabilities from risk management activities-current$
$2
$4
$3
$
$2
$4
$3
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Assets from risk management activities/Liabilities from risk management activities-current$236
$201
$486
$482
$270
$254
$486
$482
Other deferred charges and assets/Other deferred credits and liabilities102
86
66
81
115
103
66
81
Total derivatives not designated as hedging instruments$338
$287
$552
$563
$385
$357
$552
$563
Gross amounts of recognized$342
$291
$581
$569
$389
$360
$581
$569
Gross amounts offset(*)
$(196)$(267)$(435)$(497)$(251)$(327)$(435)$(497)
Net amounts recognized in the Balance Sheets$146
$24
$146
$72
$138
$33
$146
$72
(*)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $71$76 million and $62 million as of JuneSeptember 30, 2017 and December 31, 2016, respectively.

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

At JuneSeptember 30, 2017 and December 31, 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at June 30, 2017
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2017Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2017
Derivative Category and Balance Sheet
Location
Southern
Company(b)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(b)
Southern
Company(b)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(c)
(in millions) (in millions) 
Energy-related derivatives:  
Other regulatory assets, current$(24)$(3)$
$(15)$(5)$(1)$(18)$(1)$
$(13)$(3)$(1)
Other regulatory assets, deferred(23)(2)(5)(13)(3)
(12)(1)(1)(9)(1)
Other regulatory liabilities, current(a)
13
3
6


4
14
3
7


4
Other regulatory liabilities, deferred(b)
2
1
1



Total energy-related derivative gains (losses)$(34)$(2)$1
$(28)$(8)$3
$(14)$2
$7
$(22)$(4)$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 $1 million at JuneSeptember 30, 2017.

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

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016
Derivative Category and Balance Sheet
Location
Southern
Company(c)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(c)
 (in millions) 
Energy-related derivatives:      
Other regulatory assets, current$(16)$(1)$
$(9)$(5)$(1)
Other regulatory assets, deferred(19)

(16)(3)
Other regulatory liabilities, current(a)
56
8
29
1
1
17
Other regulatory liabilities, deferred(b)
12
4
7


1
Total energy-related derivative gains (losses)$33
$11
$36
$(24)$(7)$17
(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 million at December 31, 2016.

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

For the three months ended JuneSeptember 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
Derivatives in Cash Flow
Hedging Relationships
Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)
 
Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)
 
Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
Statements of Income LocationAmount Statements of Income LocationAmount
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Southern Company              
Energy-related derivatives$(9) $
 Depreciation and amortization$(2) $
$(6) $
 Depreciation and amortization$(6) $1
Interest rate derivatives(1) 6
 Interest expense, net of amounts capitalized(5) (4)(1) (6) Interest expense, net of amounts capitalized(5) (6)
Foreign currency derivatives71
 (39) Interest expense, net of amounts capitalized(5) (1)46
 37
 Interest expense, net of amounts capitalized(5) (6)
    
Other income (expense), net(*)
79
 (20)    
Other income (expense), net(*)
43
 7
Total$61
 $(33) $67
 $(25)$39
 $31
 $27
 $(4)
Alabama Power              
Interest rate derivatives$
 $
 Interest expense, net of amounts capitalized$(2) $(2)$
 $
 Interest expense, net of amounts capitalized$(2) $(2)
Georgia Power              
Interest rate derivatives$
 $
 Interest expense, net of amounts capitalized$(1) $(1)$
 $
 Interest expense, net of amounts capitalized$(1) $(1)
Gulf Power       
Mississippi Power       
Interest rate derivatives$(1) $(2) Interest expense, net of amounts capitalized$
 $
$(1) $(1) Interest expense, net of amounts capitalized$
 $
Southern Power              
Energy-related derivatives$(7) $
 Depreciation and amortization$(2) $
$(6) $
 Depreciation and amortization$(6) $1
Foreign currency derivatives71
 (39) Interest expense, net of amounts capitalized(5) (1)46
 37
 Interest expense, net of amounts capitalized(5) (6)
    
Other income (expense), net(*)
79
 (20)    
Other income (expense), net(*)
43
 7
Total$64
 $(39) $72
 $(21)$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 Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor threenine months ended June 30, 2017 and the predecessor three months ended June 30, 2016 were as follows:

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 RelationshipsThree Months Ended June 30, 2017

Three Months Ended June 30, 2016
Statements of Income LocationThree Months Ended June 30, 2017

Three Months Ended June 30, 2016

(in millions)

(in millions)

(in millions)

(in millions)
Energy-related derivatives$(2)

$

Cost of natural gas$


$(1)
Interest rate derivatives


(19)
Interest expense, net of amounts capitalized


(1)
Total$(2)

$(19)

$


$(2)

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

For the six months ended JuneSeptember 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:
Derivatives in Cash Flow
Hedging Relationships
Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)
 Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)
 Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
Statements of Income LocationAmount Statements of Income LocationAmount
2017 2016 2017 20162017 2016 2017 2016
(in millions) (in millions)(in millions) (in millions)
Southern Company              
Energy-related derivatives$(20) $
 Depreciation and amortization$(6) $
$(26) $(1) Depreciation and amortization$(12) $1
Interest rate derivatives(1) (184) Interest expense, net of amounts capitalized(10) (7)(2) (189) Interest expense, net of amounts capitalized(15) (13)
Foreign currency derivatives67
 (39) Interest expense, net of amounts capitalized(12) (1)114
 (1) Interest expense, net of amounts capitalized(17) (7)
    
Other income (expense), net(*)
96
 (20)    
Other income (expense), net(*)
139
 (13)
Total$46
 $(223) $68
 $(28)$86
 $(191) $95
 $(32)
Alabama Power              
Interest rate derivatives$
 $(4) Interest expense, net of amounts capitalized$(3) $(3)$
 $(3) Interest expense, net of amounts capitalized$(5) $(5)
Georgia Power              
Interest rate derivatives$
 $
 Interest expense, net of amounts capitalized$(3) $(2)$
 $
 Interest expense, net of amounts capitalized$(3) $(3)
Gulf Power              
Energy-related derivatives$(1) $
 Depreciation and amortization$
 $
$(1) $
 Depreciation and amortization$
 $
Interest rate derivatives(1) (7) Interest expense, net of amounts capitalized
 
(1) (7) Interest expense, net of amounts capitalized
 
Total$(2) $(7) $
 $
$(2) $(7) $
 $
Mississippi Power              
Interest rate derivatives$
 $
 Interest expense, net of amounts capitalized$(1) $(1)$
 $(1) Interest expense, net of amounts capitalized$(1) $(1)
Southern Power              
Energy-related derivatives$(15) $
 Depreciation and amortization$(6) $
$(21) $(1) Depreciation and amortization$(12) $1
Interest rate derivatives
 
 Interest expense, net of amounts capitalized
 (1)
 
 Interest expense, net of amounts capitalized
 (1)
Foreign currency derivatives67
 (39) Interest expense, net of amounts capitalized(12) (1)114
 (1) Interest expense, net of amounts capitalized(17) (7)


 

 
Other income (expense), net(*)
96
 (20)

 

 
Other income (expense), net(*)
139
 (13)
Total$52
 $(39) $78
 $(22)$93
 $(2) $110
 $(20)
(*)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 Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor sixnine months ended JuneSeptember 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor six months endedperiod of January 1, 2016 through June 30, 2016 were as follows:
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Successor  Predecessor Successor  Predecessor
Gain (Loss) Recognized in OCI on Derivative
(Effective Portion)
 Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging RelationshipsSix Months Ended June 30, 2017  Six Months Ended June 30, 2016 Statements of Income LocationSix Months Ended June 30, 2017  Six Months Ended June 30, 2016Nine Months Ended September 30, 2017 Statements of Income LocationNine Months Ended September 30, 2017
(in millions)  (in millions) (in millions)  (in millions)(in millions) (in millions)
Energy-related derivatives$(4)  $
 Cost of natural gas$
  $(1)$(4) Cost of natural gas$
Interest rate derivatives
  (64) Interest expense, net of amounts capitalized
  
Total$(4)  $(64) $
  $(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 sixnine months ended JuneSeptember 30, 2017 and 2016, 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 sixnine months ended JuneSeptember 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 were as follows:
 Gain (Loss) Gain (Loss)
 Three Months Ended
June 30,
 Six Months Ended
June 30,
 Three Months Ended September 30, Nine Months Ended September 30,
Derivatives in Non-Designated Hedging RelationshipsStatements of Income Location20172016 20172016Statements of Income Location20172016 20172016
 (in millions) (in millions) (in millions) (in millions)
Southern Company        
Energy Related derivatives:
Natural gas revenues(*)
$16
$
 $65
$
Natural gas revenues(*)
$(17)$
 $48
$
Cost of natural gas(2)
 (4)
Cost of natural gas2
6
 (2)6
Total derivatives in non-designated hedging relationshipsTotal derivatives in non-designated hedging relationships$14
$
 $61
$
Total derivatives in non-designated hedging relationships$(15)$6
 $46
$6
(*)Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $1 million and $15 million for the three and sixnine months ended JuneSeptember 30, 2017 respectively.and immaterial amounts for all other periods presented.

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

 Gain (Loss) Gain (Loss)
 Successor

Predecessor Successor  Predecessor Successor
Successor Successor Successor  Predecessor
Derivatives in Non-Designated Hedging RelationshipsStatements of Income LocationThree Months Ended
June 30, 2017
  Three Months Ended
June 30, 2016
 Six Months Ended June 30, 2017  
Six
Months Ended
June 30, 2016
Statements 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) (in millions) (in millions) (in millions) (in millions)   
Southern Company Gas          Southern Company Gas          
Energy Related derivatives:
Natural gas revenues(*)
$16
  $(21) $65
  $(1)
Natural gas revenues(*)
$(17) $
 $48
 $
  $(1)
Cost of natural gas(2)  (61) (4)  (62)Cost of natural gas2
 6
 (2) 6
  (62)
Total derivatives in non-designated hedging relationshipsTotal derivatives in non-designated hedging relationships$14
  $(82) $61
  $(63)Total derivatives in non-designated hedging relationships$(15) $6
 $46
 $6
  $(63)
(*)Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor sixnine months ended JuneSeptember 30, 2017 and immaterial amounts for all other periods presented.

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

For the three and sixnine months ended JuneSeptember 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
For the three and sixnine months ended JuneSeptember 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) Gain (Loss)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 Three Months Ended September 30,Nine Months Ended September 30,
Derivative CategoryStatements of Income Location2017 20162017 2016Statements of Income Location2017 20162017 2016
 (in millions) (in millions)
Southern Company            
Interest rate derivatives:Interest expense, net of amounts capitalized$7
 $4
$(1) $24
Interest expense, net of amounts capitalized$(5) $(9)$(6) $15
Georgia Power            
Interest rate derivatives:Interest expense, net of amounts capitalized$
 $
$(1) $15
Interest expense, net of amounts capitalized$
 $(5)$(1) $10
For the three and sixnine months ended JuneSeptember 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 JuneSeptember 30, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
At JuneSeptember 30, 2017, the fair value of derivative liabilities with contingent features was immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $11 millionimmaterial for Southern Company, $10 million for the traditional electric operating companies and Southern Power, and $1 million for Southern Company Gas.all registrants. The maximum potential collateral

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

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 JuneSeptember 30, 2017, 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 JuneSeptember 30, 2017, cash collateral held on deposit in broker margin accounts was $71$76 million.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern

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 Gasconducts 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)ACQUISITIONS AND DISPOSITIONS
Southern Company
Merger with Southern Company Gas
Southern Company Gas is 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 total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.
The Merger was accounted for using the acquisition method of accounting with the assets acquired 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 $716$565 million and $2.3$2.8 billion and net income of $49$15 million and $288$303 million for the three and sixnine months ended JuneSeptember 30, 2017, respectively.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 acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement 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 fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.

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

For the Six Months Ended June 30,For the Nine Months Ended September 30,
20162016
Operating revenues (in millions)
$10,346
$16,609
Net income attributable to Southern Company (in millions)
$1,255
$2,394
Basic Earnings Per Share (EPS)$1.34
$2.52
Diluted EPS$1.33
$2.51
These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.
Acquisition of PowerSecure
On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
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 2 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.
Acquisitions During the SixNine Months Ended JuneSeptember 30, 2017
During the sixnine months ended JuneSeptember 30, 2017, in accordance with Southern Power's overall growth strategy, Southern Renewable Partnerships, LLC (SRP), one of Southern Power's wholly-owned subsidiaries acquired the Bethel wind facility.project discussed below. 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
The aggregate amounts of revenue and net income excluding impacts from PTCs, 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 Bethel 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 finalized during the sixnine months ended JuneSeptember 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.
Acquisitions Subsequent to June 30, 2017
Subsequent to JuneSeptember 30, 2017, Southern Power acquired a 100% ownership interest in and commenced constructionpurchased all of the Cactus Flats 148-MW wind facility,redeemable noncontrolling interests, representing 10% of the majoritymembership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of which is covered by two PPAs, which expire in 2030 and 2033. The facility is expectednotes payable to be placed in service in mid-2018. The ultimate outcome of this matter cannot be determined at this time.Turner Renewable Energy, LLC.
Construction Projects Completed and in Progress
During the sixnine months ended JuneSeptember 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through JuneSeptember 30, 2017, total costs of construction incurred for these projects were $421$494 million, of which $49$122 million remained in CWIP for the Mankato facility acquired in 2016.CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be $170between $360 million to $190and $415 million for the Mankato facility.and Cactus Flats facilities. The ultimate outcome of this matterthese matters cannot be determined at this time.
Project FacilityResource
Approximate Nameplate Capacity (MW)
LocationActual/Expected CODPPA Contract Period
Projects Completed During the SixNine Months Ended JuneSeptember 30, 2017
East PecosSolar120Pecos County, TXMarch 201715 years
LamesaSolar102Dawson County, TXApril 201715 years
      
ProjectProjects Under Construction as of JuneSeptember 30, 2017
Cactus Flats(*)
Wind148Concho County, TXThird quarter 201812-15 years
MankatoNatural Gas345Mankato, MNSecond quarter 201920 years
(*)On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.

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

Development Projects
In December 2016, as part of Southern Power's renewable development strategy, SRPone of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.
Southern Company Gas
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. for a total cash purchase price of $1.7 billion. 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.
(J)JOINT OWNERSHIP AGREEMENTS
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)

Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of JuneSeptember 30, 2017 and December 31, 2016 and related income from those investments for the successor three and sixnine month periods ended JuneSeptember 30, 2017, the successor three-month period ended September 30, 2016, and for the predecessor three and six month periods endedperiod January 1, 2016 through June 30, 2016 were as follows:
 
Balance Sheet InformationJune 30, 2017December 31, 2016September 30, 2017December 31, 2016
(in millions)(in millions)
SNG$1,405
$1,394
$1,385
$1,394
Atlantic Coast Pipeline53
33
61
33
PennEast Pipeline45
22
49
22
Triton43
44
43
44
Pivotal JAX LNG, LLC32
16
40
16
Horizon Pipeline31
30
30
30
Other1
2
1
2
Total$1,610
$1,541
$1,609
$1,541
Successor  Predecessor Successor  PredecessorSuccessorSuccessorSuccessorPredecessor
Income Statement InformationThree Months Ended June 30, 2017  Three Months Ended June 30, 2016 Six Months Ended June 30, 2017  Six Months Ended June 30, 2016Three Months Ended September 30, 2017Three Months Ended September 30, 2016Nine Months Ended September 30, 2017January 1, 2016 through June 30, 2016
(in millions)  (in millions) (in millions)  (in millions)(in millions)(in millions)
SNG$24
  $
 $58
  $
$28
$27
$86
$
Triton2
  1
 2
  1
PennEast Pipeline1
  
 4
  
1

5

Atlantic Coast Pipeline2
  
 3
  
1
1
4

Triton1
1
3
1
Horizon Pipeline
  
 1
  1
1

2
1
Total$29
  $1
 $68
  $2
$32
$29
$100
$2
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

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

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 sixnine months ended JuneSeptember 30, 2017 and for the period September 1, 2016 through September 30, 2016 is as follows:
Income Statement InformationThree Months Ended June 30, 2017Six Months Ended June 30, 2017Three Months Ended September 30, 2017Nine Months Ended September 30, 2017September 1, 2016 through September 30, 2016
(in millions)(in millions)
Revenues$143
$298
$146
$445
$82
Operating income$63
$147
$71
$218
$60
Net income$48
$114
$57
$172
$55

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

(K) 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 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 seven 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.
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 $90$105 million and $190$295 million for the three and sixnine months ended JuneSeptember 30, 2017, respectively, and $107$110 million and $204$313 million for the three and sixnine months ended JuneSeptember 30, 2016, 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 sixnine months ended JuneSeptember 30, 2017 and 2016 was as follows:
Electric Utilities Electric Utilities 
Traditional
Electric Operating
Companies
Southern
Power
EliminationsTotalSouthern Company Gas
All
Other
EliminationsConsolidated
Traditional
Electric Operating
Companies
Southern
Power
EliminationsTotalSouthern Company Gas
All
Other
EliminationsConsolidated
(in millions)(in millions)
Three Months Ended
June 30, 2017:
 
Three Months Ended
September 30, 2017:
 
Operating revenues$4,157
$529
$(101)$4,585
$716
$166
$(37)$5,430
$5,017
$618
$(112)$5,523
$565
$153
$(40)$6,201
Segment net income (loss)(a)(b)
(1,442)82

(1,360)49
(68)(2)(1,381)1,008
124

1,132
15
(80)2
1,069
Six Months Ended
June 30, 2017:
 
Nine Months Ended
September 30, 2017:
 

 
Operating revenues$7,943
$979
$(206)$8,716
$2,276
$289
$(79)$11,202
$12,960
$1,597
$(318)$14,239
$2,841
$442
$(119)$17,403
Segment net income (loss)(a)(b)(c)
(1,010)151

(859)288
(152)
(723)
276

276
303
(232)
347
Total assets at June 30, 2017$71,503
$14,703
$(317)$85,889
$21,809
$2,348
$(1,362)$108,684
Three Months Ended
June 30, 2016:
 
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$4,115
$373
$(109)$4,379
$
$125
$(45)$4,459
$5,236
$500
$(117)$5,619
$543
$139
$(37)$6,264
Segment net income (loss)(a)(b)
599
89

688

(61)(4)623
1,022
176

1,198
4
(62)(1)1,139
Six Months Ended
June 30, 2016:
 
Nine Months Ended
September 30, 2016:
 
Operating revenues$7,884
$688
$(212)$8,360
$
$172
$(81)$8,451
$13,120
$1,189
$(330)$13,979
$543
$311
$(118)$14,715
Segment net income (loss)(a)(b)
1,064
139

1,203

(84)(7)1,112
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
$72,141
$15,169
$(316)$86,994
$21,853
$2,474
$(1,624)$109,697
(a)Attributable to Southern Company.
(b)
Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.0 billion$34 million ($2.1 billion21 million after tax) and $81$88 million ($5054 million after tax) for the three months ended JuneSeptember 30, 2017 and 2016, respectively, and $3.1$3.2 billion ($2.2 billion after tax) and $134$222 million ($83137 million after tax) for the sixnine months ended JuneSeptember 30, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined CycleKemper IGCC Schedule and Cost Estimate" for additional information.
(c)
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 sixnine months ended JuneSeptember 30, 2017. See Note (B) under "Regulatory MattersGulf PowerRetail Base Rate Cases" for additional information.
Products and Services
  Electric Utilities' Revenues
Period Retail Wholesale Other Total
  (in millions)
Three Months Ended June 30, 2017 $3,777
 $618
 $190
 $4,585
Three Months Ended June 30, 2016 3,748
 446
 185
 4,379
         
Six Months Ended June 30, 2017 $7,171
 $1,149
 $396
 $8,716
Six Months Ended June 30, 2016 7,124
 842
 394
 8,360
  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)

 Southern Company Gas' Revenues
PeriodGas
Distribution
Operations
Gas
Marketing
Services
OtherTotal
 (in millions)
Three Months Ended June 30, 2017$557
$166
$(7)$716
Six Months Ended June 30, 2017$1,689
$454
$133
$2,276
 Southern Company Gas' Revenues
PeriodGas
Distribution
Operations
Gas
Marketing
Services
OtherTotal
 (in millions)
Three Months Ended September 30, 2017$430
$143
$(8)$565
Nine Months Ended September 30, 2017$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. 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. 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 and six months ended JuneSeptember 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 three and six months endedperiod of January 1, 2016 through June 30, 2016 was as follows:
Gas Distribution OperationsGas Marketing Services
Wholesale Gas Services(*)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidatedGas Distribution OperationsGas Marketing Services
Wholesale Gas Services(*)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidated
(in millions)(in millions)
Successor – Three Months Ended June 30, 2017: 
Successor – Three Months Ended September 30, 2017:Successor – Three Months Ended September 30, 2017: 
Operating revenues$603
$166
$(12)$12
$769
$3
$(56)$716
$472
$143
$(24)$16
$607
$2
$(44)$565
Segment net income54
4
(17)9
50
(1)
49
52
1
(23)14
44
(29)
15
Successor – Six Months Ended June 30, 2017: 
Successor – Nine Months Ended September 30, 2017:Successor – Nine Months Ended September 30, 2017: 
Operating revenues$1,783
$454
$119
$37
$2,393
$5
$(122)$2,276
$2,255
$597
$95
$53
$3,000
$7
$(166)$2,841
Segment net income171
35
51
25
282
6

288
223
36
28
38
325
(22)
303
Successor – Total assets at
June 30, 2017
$18,257
$2,093
$989
$2,381
$23,720
$11,182
$(13,093)$21,809
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)

Gas Distribution OperationsGas Marketing Services
Wholesale Gas Services(*)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidatedGas Distribution OperationsGas Marketing Services
Wholesale Gas Services(*)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidated
(in millions)(in millions)
Predecessor – Three Months Ended June 30, 2016: 
Successor – Three Months Ended September 30, 2016:Successor – Three Months Ended September 30, 2016: 
Operating revenues$547
$149
$(95)$10
$611
$2
$(42)$571
$455
$126
$(8)$13
$586
$2
$(45)$543
Segment EBIT118
29
(112)(5)30
(55)1
(24)
Predecessor – Six Months Ended June 30, 2016: 
Segment net income (loss)27
(4)(11)14
26
(22)
4
Predecessor – January 1, 2016 through June 30, 2016:Predecessor – January 1, 2016 through June 30, 2016: 
Operating revenues$1,575
$435
$(32)$25
$2,003
$4
$(102)$1,905
$1,575
$435
$(32)$25
$2,003
$4
$(102)$1,905
Segment EBIT353
109
(68)(6)388
(60)
328
353
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
$19,453
$2,084
$1,127
$2,211
$24,875
$11,145
$(14,167)$21,853
(*)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 June 30, 2017$1,531
 $123
 $1,654
 $1,666
 $(12)
Successor – Six Months Ended June 30, 20173,370
 259
 3,629
 3,510
 119
Predecessor – Three Months Ended June 30, 2016$1,061
 $58
 $1,119
 $1,214
 $(95)
Predecessor – Six Months Ended June 30, 20162,500
 143
 2,643
 2,675
 (32)
 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)

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.
ItemItem 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 on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and 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 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 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 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.
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 (i) 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, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.
provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.
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 July 31,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


$400 $386 million, of which $354$340 million had been paid or accrued as of JuneSeptember 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183$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). In addition, the Vogtle Owners could terminate the Vogtle 3 and 4 Agreement for certain breaches by the EPC Contractor, including abandonment of work by the EPC Contractor.


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 June 23,August 10, 2017, Toshiba released a revised outlookits financial results for fiscal year 2016,the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $5$4.5 billion as of March 31, 2017, and announced that its independent audit process was continuing.June 30, 2017. Toshiba has alsopreviously 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, are continuing to conduct comprehensive schedule and cost-to-complete assessments,entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as well as cancellation cost assessments, to determine the impact ofprimary contractor for the EPC Contractor's bankruptcy filing on theremaining construction cost and scheduleactivities 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 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 preliminary assessment results indicatecosts 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 Vogtle Construction Monitoring (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.
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.


Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 rangesis as follows:
Preliminary in-service dates   
Unit 3February 2021March 2022
Unit 4February 2022March 2023
 (in billions)
Preliminary estimated cost to complete$3.9
$4.6
CWIP as of June 30, 20174.5
 4.5
Guarantee Obligations(1.7) (1.7)
Estimated capital costs$6.7
$7.4
Vogtle Cost Settlement Agreement Revised Forecast(5.7) (5.7)
Estimated net additional capital costs$1.0
$1.7
Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.
 (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 $3.1 billion to $3.5$3.4 billion, of which approximately $1.4$1.5 billion had been incurred through JuneSeptember 30, 2017.
Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs to cancel both units is approximately $400$350 million. As a result, as of JuneSeptember 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:
Preliminary Cancellation Cost EstimateCancellation Cost Estimate
(in billions)(in billions)
CWIP as of June 30, 2017$4.5
CWIP as of September 30, 2017$4.6
Financing costs collected, net of tax1.4
1.5
Cancellation costs(*)
0.4
0.4
Total$6.3
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, and currently expects to include its recommendation in its seventeenth Vogtle Construction Monitoring report to be filed with the Georgia PSC in late August 2017.


recovery.
The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.
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.
  (4) Instruments Describing Rights(3) Articles of Security Holders, Including IndenturesIncorporation and By-Laws
     
  Southern CompanyAlabama Power
     
 *(a)(b)1-Fourth Supplemental Indenture
     

 *(a)2-Nineteenth Supplemental Indenture to Senior Note Indenture, dated as(4) Instruments Describing Rights of June 21, 2017, providing for the issuance of the Series 2017A Floating Rate Senior Notes due September 30, 2020.Security Holders, Including Indentures
     
  Georgia Power
     
  (c)1-
(c)2-
(c)3-
Gulf Power
(d)-Twenty-Second Supplemental Indenture to Senior Note Indenture, dated as of May 18, 2017, providing for the issuance of the Series 2017A 3.30% Senior Notes due May 30, 2027. (Designated in Form 8-K dated May 15, 2017, File No. 001-31737, as Exhibit 4.2.)
Southern Company Gas
(g)1-Form of Southern Company Gas Capital Corporation's Series 2017A 4.400% Senior Notes due May 30, 2047. (Designated in Form 8-K dated May 4, 2017, File No. 1-14174, as Exhibit 4.1.)
(g)2-Form of Southern Company Gas' Guarantee related to the Series 2017A 4.400% Senior Notes due May 30, 2047. (Designated in Form 8-K dated May 4, 2017, File No. 1-14174, as Exhibit 4.3.)
     
  (10) Material Contracts
   
  GeorgiaMississippi Power
     
  (c)(e)1-Amendment No. 2
  (c)2
Southern Company Gas
(g)1-Amendment No. 3 to Interim Assessment

(c)3-Amendment No. 4 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 5, 2017, File No. 1-6468, as Exhibit 10.1.)
(c)4-Amendment No. 5 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.2.)
(c)5-Amendment No. 6 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 22, 2017, File No. 1-6468, as Exhibit 10.1.)
(c)6-Amendment No. 7 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated June 28, 2017, File No. 1-6468, as Exhibit 10.1.)
(c)7-Amendment No. 8 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC. (Designated in Form 8-K dated July 20, 2017, File No. 1-6468, as Exhibit 10.1.)
(c)8-Settlement Agreement dated as of June 9, 2017, by and among Georgia Power, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Toshiba Corporation. (Designated in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.1.)
*(c)9-Amended and Restated Services Agreement dated as of June 20, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and The City of Dalton, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse and WECTEC. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filing and filed them separately with the SEC.)
     
  (24) Power of Attorney and Resolutions
     
  Southern Company
     
  (a)-
     
  Alabama Power
     
  (b)-
     

  Georgia Power
     
  (c)1-
*(c)2-
     
  Gulf Power
     
  (d)1-
*(d)2-
     
  Mississippi Power
     
  (e)-
     

  Southern Power
     
  (f)-
     
  Southern Company Gas
     
  (g)-
     
  (31) Section 302 Certifications
     
  Southern Company
     
 *(a)1-
     
 *(a)2-
     
  Alabama Power
     
 *(b)1-
     
 *(b)2-
     
  Georgia Power
     
 *(c)1-
     
 *(c)2-
     
  Gulf Power
     
 *(d)1-
     
 *(d)2-
     
  Mississippi Power
     
 *(e)1-
     

 *(e)2-
     
  Southern Power
     
 *(f)1-
     
 *(f)2-
     

  Southern Company Gas
     
 *(g)1-
     
 *(g)2-
     
  (32) Section 906 Certifications
     
  Southern Company
     
 *(a)-
     
  Alabama Power
     
 *(b)-
     
  Georgia Power
     
 *(c)-
     
  Gulf Power
     
 *(d)-
     
  Mississippi Power
     
 *(e)-
     
  Southern Power
     
 *(f)-
     
  Southern Company Gas
     
 *(g)-
     

  (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

THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  THE SOUTHERN COMPANY
    
By Thomas A. Fanning
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Art P. Beattie
  Executive Vice President and Chief Financial Officer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 1,October 31, 2017

ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  ALABAMA POWER COMPANY
    
By Mark A. Crosswhite 
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Philip C. Raymond
  Executive Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 1,October 31, 2017

GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  GEORGIA POWER COMPANY
    
By W. Paul Bowers
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By W. Ron HinsonXia Liu
  Executive Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 1,October 31, 2017

GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  GULF POWER COMPANY
    
By S. W. Connally, Jr.
  Chairman, President and Chief Executive Officer
  (Principal Executive Officer)
    
By Xia LiuRobin B. Boren
  Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 1,October 31, 2017

MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  MISSISSIPPI POWER COMPANY
    
By Anthony L. Wilson
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Moses H. Feagin
  Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 1,October 31, 2017

SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  SOUTHERN POWER COMPANY
    
By Joseph A. Miller
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By William C. Grantham
  Senior Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 1,October 31, 2017

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. Evans
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Elizabeth W. Reese
  Executive Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 1,October 31, 2017


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