Document
Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 September 30, 2017

The Southern Company
 
Par Value $5 Per Share
 
1,003,627,691

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
September 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
September 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 Proceeds
Inapplicable
Item 3.
Defaults Upon Senior Securities
Inapplicable
Item 4.
Mine Safety Disclosures
Inapplicable
Item 5.
Other Information
Inapplicable
Item 6.
 

4

Table of Contents

DEFINITIONS
Term
Meaning
 
 
2012 MPSC CPCN Order
A 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 ARP
Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDC
Allowance for funds used during construction
Alabama Power
Alabama Power Company
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Atlanta Gas Light
Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Atlantic Coast Pipeline
Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest
Baseload Act
State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
CCR
Coal 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
COD
Commercial operation date
Contractor Settlement Agreement
The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
Cooperative Energy
Electric cooperative in Mississippi formerly known as South Mississippi Electric Power Association (SMEPA)
CPCN
Certificate of public convenience and necessity
CWIP
Construction work in progress
Dalton Pipeline
A 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia
DOE
U.S. Department of Energy
ECO Plan
Mississippi Power's Environmental Compliance Overview Plan
Eligible Project Costs
Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program
EPA
U.S. Environmental Protection Agency
EPC Contractor
Westinghouse 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
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FFB
Federal Financing Bank
Fitch
Fitch Ratings, Inc.
Form 10-K
Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2016, as applicable
GAAP
U.S. generally accepted accounting principles
Georgia Power
Georgia Power Company
Gulf Power
Gulf Power Company
Heating Degree Days
A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Horizon Pipeline
Horizon Pipeline Company, LLC

5

Table of Contents

DEFINITIONS
(continued)
Term
Meaning
 
 
IGCC
Integrated coal gasification combined cycle
IIC
Intercompany interchange contract
Illinois Commission
Illinois Commerce Commission, the state regulatory agency for Nicor Gas
IRC
Internal Revenue Code of 1986, as amended
IRS
Internal Revenue Service
ITC
Investment tax credit
Kemper IGCC
Mississippi Power's IGCC project in Kemper County, Mississippi
KWH
Kilowatt-hour
LIBOR
London Interbank Offered Rate
LIFO
Last-in, first-out
LNG
Liquefied natural gas
Loan Guarantee Agreement
Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
LOCOM
Lower of weighted average cost or current market price
LTSA
Long-term service agreement
MATS rule
Mercury and Air Toxics Standards rule
Merger
The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation
Mirror CWIP
A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order
Mississippi Power
Mississippi Power Company
mmBtu
Million British thermal units
Moody's
Moody's Investors Service, Inc.
MRA
Municipal and Rural Associations
MW
Megawatt
natural gas distribution utilities
Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas)
NCCR
Georgia Power's Nuclear Construction Cost Recovery
New Jersey BPU
New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor Gas
Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC
U.S. Nuclear Regulatory Commission
NYMEX
New York Mercantile Exchange, Inc.
OCI
Other comprehensive income
PennEast Pipeline
PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest
PEP
Mississippi Power's Performance Evaluation Plan
Piedmont
Piedmont Natural Gas Company, Inc.
Pivotal Utility Holdings
Pivotal 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 4
Two new nuclear generating units under construction at Georgia Power's Plant Vogtle
PowerSecure
PowerSecure, Inc.
power pool
The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations

6

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DEFINITIONS
(continued)
Term
Meaning
 
 
PPA
Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC
Public Service Commission
PTC
Production tax credit
Rate CNP
Alabama Power's Rate Certificated New Plant
Rate CNP Compliance
Alabama Power's Rate Certificated New Plant Compliance
Rate CNP PPA
Alabama Power's Rate Certificated New Plant Power Purchase Agreement
Rate ECR
Alabama Power's Rate Energy Cost Recovery
Rate NDR
Alabama Power's Rate Natural Disaster Reserve
Rate RSE
Alabama Power's Rate Stabilization and Equalization plan
registrants
Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas
ROE
Return on equity
S&P
S&P Global Ratings, a division of S&P Global Inc.
scrubber
Flue gas desulfurization system
SCS
Southern Company Services, Inc. (the Southern Company system service company)
SEC
U.S. Securities and Exchange Commission
SNG
Southern Natural Gas Company, L.L.C.
Southern Company
The Southern Company
Southern Company Gas
Southern Company Gas and its subsidiaries
Southern Company Gas Capital
Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company system
Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (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 Nuclear
Southern Nuclear Operating Company, Inc.
Southern Power
Southern Power Company and its subsidiaries
SouthStar
SouthStar Energy Services, LLC
STRIDE
Atlanta Gas Light's Strategic Infrastructure Development and Enhancement program
Toshiba
Toshiba Corporation, parent company of Westinghouse
Toshiba Guarantee
Certain payment obligations of the EPC Contractor guaranteed by Toshiba
traditional electric operating companies
Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Triton
Triton Container Investments, LLC
Virginia Commission
Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural Gas
Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle 3 and 4 Agreement
Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4
Vogtle Owners
Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
WACOG
Weighted average cost of gas
WECTEC
WECTEC Global Project Services Inc.
Westinghouse
Westinghouse Electric Company LLC

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the 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;




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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.


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THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

10

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in millions)
 
(in millions)
Operating Revenues:
 
 
 
 
 
 
 
Retail electric revenues
$
4,615

 
$
4,808

 
$
11,786

 
$
11,932

Wholesale electric revenues
718

 
613

 
1,867

 
1,455

Other electric revenues
168

 
181

 
510

 
529

Natural gas revenues
532

 
518

 
2,746

 
518

Other revenues
168

 
144

 
494

 
281

Total operating revenues
6,201

 
6,264

 
17,403

 
14,715

Operating Expenses:
 
 
 
 
 
 
 
Fuel
1,285

 
1,400

 
3,372

 
3,334

Purchased power
256

 
227

 
646

 
581

Cost of natural gas
134

 
133

 
1,085

 
133

Cost of other sales
90

 
84

 
293

 
161

Other operations and maintenance
1,287

 
1,411

 
3,918

 
3,616

Depreciation and amortization
767

 
695

 
2,236

 
1,805

Taxes other than income taxes
303

 
309

 
941

 
821

Estimated loss on Kemper IGCC
34

 
88

 
3,155

 
222

Total operating expenses
4,156

 
4,347

 
15,646

 
10,673

Operating Income
2,045

 
1,917

 
1,757

 
4,042

Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
18

 
52

 
133

 
150

Earnings from equity method investments
32

 
29

 
100

 
28

Interest expense, net of amounts capitalized
(407
)
 
(374
)
 
(1,248
)
 
(913
)
Other income (expense), net
11

 
(8
)
 
2

 
(66
)
Total other income and (expense)
(346
)
 
(301
)
 
(1,013
)
 
(801
)
Earnings Before Income Taxes
1,699

 
1,616

 
744

 
3,241

Income taxes
590

 
439

 
317

 
917

Consolidated Net Income
1,109

 
1,177

 
427

 
2,324

Less:
 
 
 
 
 
 
 
Dividends on preferred and preference stock of subsidiaries
10

 
11

 
32

 
34

Net income attributable to noncontrolling interests
30

 
27

 
48

 
39

Consolidated Net Income Attributable to
   Southern Company
$
1,069

 
$
1,139

 
$
347

 
$
2,251

Common Stock Data:
 
 
 
 
 
 
 
Earnings per share —
 
 
 
 
 
 
 
Basic
$
1.07

 
$
1.18

 
$
0.35

 
$
2.40

Diluted
$
1.06

 
$
1.17

 
$
0.35

 
$
2.38

Average number of shares of common stock outstanding (in millions)
 
 
 
 
 
 
 
Basic
1,003

 
968

 
998

 
940

Diluted
1,010

 
975

 
1,005

 
945

Cash dividends paid per share of common stock
$
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.


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Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in millions)
 
(in millions)
Consolidated Net Income
$
1,109

 
$
1,177

 
$
427

 
$
2,324

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Changes in fair value, net of tax of $15, $12, $32, and $(74),
respectively
25

 
19

 
54

 
(118
)
Reclassification adjustment for amounts included in net income,
net of tax of $(10), $2, $(36), and $13, respectively
(17
)
 
2

 
(59
)
 
20

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

 
1

 
3

 
3

Total other comprehensive income (loss)
9

 
22

 
(2
)
 
(95
)
Comprehensive Income
1,118

 
1,199

 
425

 
2,229

Less:
 
 
 
 
 
 
 
Dividends on preferred and preference stock of subsidiaries
10

 
11

 
32

 
34

Comprehensive income attributable to noncontrolling interests
30

 
27

 
48

 
39

Consolidated Comprehensive Income Attributable to
   Southern Company
$
1,078

 
$
1,161

 
$
345

 
$
2,156

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


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Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Nine Months Ended September 30,
 
2017
 
2016
 
(in millions)
Operating Activities:
 
 
 
Consolidated net income
$
427

 
$
2,324

Adjustments to reconcile consolidated net income to net cash provided from operating activities  
 
 
 
Depreciation and amortization, total
2,564

 
2,109

Deferred income taxes
15

 
(22
)
Allowance for equity funds used during construction
(133
)
 
(150
)
Pension, postretirement, and other employee benefits
(64
)
 
(158
)
Settlement of asset retirement obligations
(137
)
 
(117
)
Hedge settlements

 
(236
)
Estimated loss on Kemper IGCC
3,148

 
222

Other, net
(8
)
 
(1
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
426

 
(458
)
-Fossil fuel for generation
59

 
204

-Natural gas for sale, net of temporary LIFO liquidation

 
(222
)
-Other current assets
(164
)
 
(112
)
-Accounts payable
(467
)
 
(9
)
-Accrued taxes
157

 
1,062

-Accrued compensation
(230
)
 
(122
)
-Retail fuel cost over recovery
(211
)
 
(106
)
-Other current liabilities
(129
)
 
88

Net cash provided from operating activities
5,253

 
4,296

Investing Activities:
 
 
 
Business acquisitions, net of cash acquired
(1,032
)
 
(9,513
)
Property additions
(5,242
)
 
(5,252
)
Investment in restricted cash
(16
)
 
(750
)
Distribution of restricted cash
33

 
746

Nuclear decommissioning trust fund purchases
(585
)
 
(838
)
Nuclear decommissioning trust fund sales
580

 
832

Cost of removal, net of salvage
(208
)
 
(155
)
Change in construction payables, net
120

 
(259
)
Investment in unconsolidated subsidiaries
(134
)
 
(1,421
)
Payments pursuant to LTSAs
(189
)
 
(125
)
Other investing activities
(14
)
 
95

Net cash used for investing activities
(6,687
)
 
(16,640
)
Financing Activities:
 
 
 
Increase (decrease) in notes payable, net
(515
)
 
655

Proceeds —
 
 
 
Long-term debt
4,068

 
14,091

Common stock
613

 
3,265

Preferred stock
250

 

Short-term borrowings
1,263

 

Redemptions and repurchases —
 
 
 
Long-term debt
(1,981
)
 
(2,405
)
Preferred and preference stock
(150
)
 

Short-term borrowings
(409
)
 
(475
)
Distributions to noncontrolling interests
(89
)
 
(22
)
Capital contributions from noncontrolling interests
79

 
367

Purchase of membership interests from noncontrolling interests

 
(129
)
Payment of common stock dividends
(1,716
)
 
(1,553
)
Other financing activities
(113
)
 
(185
)
Net cash provided from financing activities
1,300

 
13,609

Net Change in Cash and Cash Equivalents
(134
)
 
1,265

Cash and Cash Equivalents at Beginning of Period
1,975

 
1,404

Cash and Cash Equivalents at End of Period
$
1,841

 
$
2,669

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $72 and $94 capitalized for 2017 and 2016, respectively)
$
1,286

 
$
766

Income taxes, net
(187
)
 
(151
)
Noncash transactions — Accrued property additions at end of period
805

 
578

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30, 2017
 
At December 31, 2016
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
1,841

 
$
1,975

Receivables —
 
 
 
 
Customer accounts receivable
 
1,744

 
1,583

Energy marketing receivables
 
427

 
623

Unbilled revenues
 
595

 
706

Under recovered fuel clause revenues
 
62

 

Income taxes receivable, current
 
138

 
544

Other accounts and notes receivable
 
578

 
377

Accumulated provision for uncollectible accounts
 
(43
)
 
(43
)
Materials and supplies
 
1,499

 
1,462

Fossil fuel for generation
 
571

 
689

Natural gas for sale
 
631

 
631

Prepaid expenses
 
365

 
364

Other regulatory assets, current
 
585

 
581

Other current assets
 
209

 
230

Total current assets
 
9,202

 
9,722

Property, Plant, and Equipment:
 
 
 
 
In service
 
102,014

 
98,416

Less: Accumulated depreciation
 
31,164

 
29,852

Plant in service, net of depreciation
 
70,850

 
68,564

Nuclear fuel, at amortized cost
 
865

 
905

Construction work in progress
 
8,026

 
8,977

Total property, plant, and equipment
 
79,741

 
78,446

Other Property and Investments:
 
 
 
 
Goodwill
 
6,267

 
6,251

Equity investments in unconsolidated subsidiaries
 
1,637

 
1,549

Other intangible assets, net of amortization of $156 and $62
at September 30, 2017 and December 31, 2016, respectively
 
902

 
970

Nuclear decommissioning trusts, at fair value
 
1,783

 
1,606

Leveraged leases
 
788

 
774

Miscellaneous property and investments
 
236

 
270

Total other property and investments
 
11,613

 
11,420

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
1,318

 
1,629

Unamortized loss on reacquired debt
 
210

 
223

Other regulatory assets, deferred
 
6,718

 
6,851

Other deferred charges and assets
 
1,513

 
1,406

Total deferred charges and other assets
 
9,759

 
10,109

Total Assets
 
$
110,315

 
$
109,697

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


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholders' Equity
 
At September 30, 2017
 
At December 31, 2016
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
3,505

 
$
2,587

Notes payable
 
2,579

 
2,241

Energy marketing trade payables
 
451

 
597

Accounts payable
 
2,353

 
2,228

Customer deposits
 
550

 
558

Accrued taxes —
 
 
 
 
Accrued income taxes
 
176

 
193

Unrecognized tax benefits
 
17

 
385

Other accrued taxes
 
690

 
667

Accrued interest
 
443

 
518

Accrued compensation
 
703

 
915

Asset retirement obligations, current
 
245

 
378

Acquisitions payable
 

 
489

Other regulatory liabilities, current
 
139

 
236

Other current liabilities
 
752

 
925

Total current liabilities
 
12,603

 
12,917

Long-term Debt
 
44,042

 
42,629

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
14,321

 
14,092

Accumulated deferred ITCs
 
2,290

 
2,228

Employee benefit obligations
 
2,139

 
2,299

Asset retirement obligations, deferred
 
4,356

 
4,136

Other cost of removal obligations
 
2,708

 
2,748

Other regulatory liabilities, deferred
 
449

 
476

Other deferred credits and liabilities
 
1,048

 
1,278

Total deferred credits and other liabilities
 
27,311

 
27,257

Total Liabilities
 
83,956

 
82,803

Redeemable Preferred Stock of Subsidiaries
 
361

 
118

Redeemable Noncontrolling Interests
 
59

 
164

Stockholders' Equity:
 
 
 
 
Common Stockholders' Equity:
 
 
 
 
Common stock, par value $5 per share —
 
 
 
 
Authorized — 1.5 billion shares
 
 
 
 
Issued — September 30, 2017: 1.0 billion shares
 
 
 
 
— December 31, 2016: 991 million shares
 
 
 
 
Treasury — September 30, 2017: 0.9 million shares
 
 
 
 
    — December 31, 2016: 0.8 million shares
 
 
 
 
Par value
 
5,018

 
4,952

Paid-in capital
 
10,300

 
9,661

Treasury, at cost
 
(35
)
 
(31
)
Retained earnings
 
8,981

 
10,356

Accumulated other comprehensive loss
 
(182
)
 
(180
)
Total Common Stockholders' Equity
 
24,082

 
24,758

Preferred and Preference Stock of Subsidiaries
 
462

 
609

Noncontrolling Interests
 
1,395

 
1,245

Total Stockholders' Equity
 
25,939

 
26,612

Total Liabilities and Stockholders' Equity
 
$
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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2017 vs. THIRD 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.
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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject 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.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the 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 September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

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

Nuclear Construction
On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). 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 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 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.
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 cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Construction ProgramNuclear 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.

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

RESULTS OF OPERATIONS
Net Income
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(70)
 
(6.1)
 
$(1,904)
 
(84.6)
Consolidated net income attributable to Southern Company was $1.07 billion ($1.07 per share) for the third quarter 2017 compared to $1.14 billion ($1.18 per share) for the corresponding period in 2016. 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 attributable to Southern Company was $347 million ($0.35 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 $3.2 billion and $222 million for year-to-date 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was an increase of $299 million in net income from Southern Company Gas reflecting the nine-month period in 2017 compared to the three-month period following the Merger closing on July 1, 2016, higher retail electric revenues resulting from increases in base rates, and increases in renewable energy sales at Southern Power, partially offset by a decrease in retail electric revenues due to milder weather and lower customer usage, higher interest expense, and an increase in 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
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 third quarter 2017, retail electric revenues were $4.6 billion compared to $4.8 billion for the corresponding period in 2016. For year-to-date 2017, retail electric revenues were $11.8 billion compared to $11.9 billion for the corresponding period in 2016.
Details of the changes in retail electric revenues were as follows:
 
 
Third Quarter 2017
 
Year-to-Date 2017
 
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail electric – prior year
 
$
4,808

 
 
 
$
11,932

 
 
Estimated change resulting from –
 
 
 
 
 
 
 
 
Rates and pricing
 
138

 
2.9

 
338

 
2.8

Sales decline
 
(52
)
 
(1.1
)
 
(74
)
 
(0.6
)
Weather
 
(162
)
 
(3.4
)
 
(351
)
 
(2.9
)
Fuel and other cost recovery
 
(117
)
 
(2.4
)
 
(59
)
 
(0.5
)
Retail electric – current year
 
$
4,615

 
(4.0
)%
 
$
11,786

 
(1.2
)%
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 a Rate RSE increase at Alabama Power effective

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

January 1, 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an increase in retail base revenues effective July 2017 and in environmental cost recovery effective November 2016 at Gulf Power.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " Georgia Power Rate Plans," and " – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.0% and 0.6% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales decreased 0.5% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily in the paper sector, partially offset by increased sales in the primary metals and textile 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.
Fuel and other cost recovery revenues decreased $117 million and $59 million in the third quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to lower 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
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. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, Southern Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, 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.

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

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
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$24
 
16.7
 
$213
 
75.8
In the third quarter 2017, other revenues were $168 million compared to $144 million for the corresponding period in 2016. For year-to-date 2017, other revenues were $494 million compared to $281 million for the corresponding

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

period in 2016. These increases were primarily due to increases of $5 million and $135 million for the third quarter and year-to-date 2017, respectively, from products and services at PowerSecure, which was acquired on May 9, 2016, and $8 million and $70 million for the third quarter and year-to-date 2017, respectively, of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, revenues from certain non-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
 
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
$
(115
)
 
(8.2)
 
$
38

 
1.1
Purchased power
29

 
12.8
 
65

 
11.2
Total fuel and purchased power expenses
$
(86
)
 
 
 
$
103

 
 
In the third quarter 2017, total fuel and purchased power expenses were $1.5 billion compared to $1.6 billion for the corresponding period in 2016. The decrease was primarily the result of a $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.
For year-to-date 2017, total fuel and purchased power expenses were $4.0 billion compared to $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 a $174 million decrease in 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:
 
Third Quarter 2017
 
Third Quarter 2016
 
Year-to-Date 2017
 
Year-to-Date 2016
Total generation (in billions of KWHs)
54
 
56
 
147
 
145
Total purchased power (in billions of KWHs)
6
 
6
 
14
 
15
Sources of generation (percent) —
 
 
 
 
 
 
 
Coal
31
 
38
 
30
 
33
Nuclear
15
 
15
 
16
 
16
Gas
47
 
44
 
46
 
46
Hydro
2
 
1
 
2
 
3
Other
5
 
2
 
6
 
2
Cost of fuel, generated (in cents per net KWH) 
 
 
 
 
 
 
 
Coal
2.82
 
2.97
 
2.82
 
3.10
Nuclear
0.80
 
0.81
 
0.80
 
0.82
Gas
2.92
 
2.74
 
2.93
 
2.40
Average cost of fuel, generated (in cents per net KWH)
2.54
 
2.54
 
2.51
 
2.38
Average cost of purchased power (in cents per net KWH)(*)
4.96
 
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 third quarter 2017, fuel expense was $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to a 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 1.2% increase in the volume of KWHs generated by natural gas.
For year-to-date 2017, fuel expense was $3.4 billion compared to $3.3 billion for the corresponding period in 2016. The increase was primarily due to a 22.1% increase in the average cost of natural gas per KWH generated, partially offset by a 9.0% decrease in the average cost of coal per KWH generated, a 7.4% decrease in the volume of KWHs generated by coal, and a 3.7% decrease in the volume of KWHs generated by natural gas.
Purchased Power
In the third quarter 2017, purchased power expense was $256 million compared to $227 million for the corresponding period in 2016. The increase was primarily due to a 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 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. In the third quarter 2017, cost of natural gas was $134 million compared to $133 million for the corresponding period in 2016. For year-to-date 2017, 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
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 third quarter 2017, cost of other sales was $90 million compared to $84 million for the corresponding period in 2016. For year-to-date 2017, cost of other sales was $293 million compared to $161 million for the corresponding period in 2016. The year-to-date increase primarily reflects 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 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
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 third quarter 2017, other operations and maintenance expenses were $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $37 million in maintenance costs, $9 million in customer accounts, service, and sales costs, and $8 million in other employee compensation and benefits. Other factors include a $40 million decrease in acquisition-related expenses and a $31 million decrease in employee compensation and benefits including pension costs.
For year-to-date 2017, other operations and maintenance expenses were $3.9 billion compared to $3.6 billion for the corresponding period in 2016. The increase was primarily due to increases of $420 million and $32 million in operations and maintenance expenses as a result of the inclusion of Southern Company Gas and PowerSecure results for the nine-month period in 2017, respectively, a $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 due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $79 million in maintenance costs and $34 million in other employee compensation and benefits. Other factors

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include a $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 scheduled outage and maintenance costs at 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 Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.
Depreciation and Amortization
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$72
 
10.4
 
$431
 
23.9
In the third quarter 2017, depreciation and amortization was $767 million compared to $695 million for the corresponding period in 2016. The increase is primarily related to additional plant in service at the traditional electric operating companies, Southern Power, and Southern Company Gas.
For year-to-date 2017, depreciation and amortization was $2.2 billion compared to $1.8 billion for the corresponding period in 2016. The increase reflects $254 million as a result of the inclusion of Southern Company Gas for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects $170 million related to additional plant in service at the traditional electric operating companies and Southern Power. The increase was partially offset by a $34 million increase in the reductions in depreciation authorized in Gulf Power's 2013 rate case settlement approved by the Florida PSC as compared to the corresponding period in 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 Notes (B) and (I) to the Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base Rate Cases" and "Southern CompanyMerger with Southern Company Gas," respectively, herein for additional information.
Taxes Other Than Income Taxes
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(6)
 
(1.9)
 
$120
 
14.6
For year-to-date 2017, taxes other than income taxes were $941 million compared to $821 million for the corresponding period in 2016. The increase primarily reflects the inclusion of Southern Company Gas taxes 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Estimated Loss on Kemper IGCC
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(54)
 
(61.4)
 
$2,933
 
N/M
N/M - Not meaningful
Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded at Mississippi Power in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate 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 for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).
See FUTURE EARNINGS POTENTIAL – "Construction 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
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 third quarter 2017, AFUDC equity was $18 million compared to $52 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $133 million compared to $150 million in the corresponding period in 2016. These decreases primarily resulted from Mississippi Power's suspension of the Kemper IGCC project 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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compared to $28 million in the corresponding period in 2016. These increases were primarily related to Southern Company Gas' equity method investment in SNG in September 2016.
See Note 12 to the financial statements of Southern Company under "Southern Company – Investment in Southern Natural Gas" in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$33
 
8.8
 
$335
 
36.7
In the third quarter 2017, interest expense, net of amounts capitalized was $407 million compared to $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 $1.2 billion compared to $913 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $31 million decrease in interest capitalized, 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 Experimental Deduction" and Notes (E) and (G) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$19
 
N/M
 
$68
 
N/M
N/M - Not meaningful
In the third quarter 2017, other income (expense), net was $11 million compared to $(8) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $2 million compared to $(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 $36 million and $152 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the third quarter and year-to-date 2017, respectively, fully offset 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
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 third quarter 2017, income taxes 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 benefits from solar ITCs at Southern Power, a $23 million increase in deferred income tax expenses associated with new State of Illinois 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 $866 million in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power, partially offset by a $226 million increase reflecting the nine-month period of income taxes at Southern Company Gas in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016 and a $44 million net decrease in tax benefits from renewable tax credits at Southern Power.
See Notes (B), (G), and (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. Matters related to Plant Vogtle Units 3 and 4 construction and rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in current rates are also major factors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and 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 the pace of economic growth that may be affected by changes in regional and global economic conditions, which may

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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.
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 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 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.
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 – 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 nine months ended September 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.
In 2015, the Florida PSC approved Gulf Power's three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.
Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020.
The ultimate outcome of these matters cannot be determined at this time.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K 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. 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%) 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 in December 2017, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. Following Mississippi Power's suspension of the Kemper IGCC construction, the largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). In August 2017, Georgia Power filed its seventeenth VCM report with the Georgia PSC, in which it recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these and other related matters by February 6, 2018. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates.
For additional information, see Note 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 " Southern Company Gas Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" herein. Also see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein.
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 MPUS, authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension,

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

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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 of an appeal.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear 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 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, 2017
4.6

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 tax
1.5

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

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
Company
2017
2018
2019
2020
2022
 
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 Power
30

195

25

30


 
280

 
280

 
45

 

 

 
40

Mississippi Power
100





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

See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) 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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:
 
 
Short-term Debt at September 30, 2017
 
Short-term Debt During the Period(*)
 
 
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 Ratings
Maximum 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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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 Power
550

 
200

 
36

 

 

Georgia Power
1,350

 
450

 
65

 
370

 
13

Gulf Power
300

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

Also in August 2017, Southern Company repaid at maturity $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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the 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.

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ALABAMA POWER COMPANY

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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-affiliates
77

 
82

 
210

 
211

Wholesale revenues, affiliates
18

 
18

 
83

 
49

Other revenues
50

 
56

 
158

 
162

Total operating revenues
1,740

 
1,785

 
4,606

 
4,561

Operating Expenses:
 
 
 
 
 
 
 
Fuel
343

 
410

 
944

 
973

Purchased power, non-affiliates
57

 
63

 
132

 
139

Purchased power, affiliates
55

 
41

 
117

 
129

Other operations and maintenance
391

 
348

 
1,134

 
1,097

Depreciation and amortization
185

 
177

 
549

 
524

Taxes other than income taxes
93

 
96

 
284

 
286

Total operating expenses
1,124

 
1,135

 
3,160

 
3,148

Operating Income
616

 
650

 
1,446

 
1,413

Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
11

 
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 Taxes
546

 
575

 
1,236

 
1,196

Income taxes
216

 
219

 
493

 
462

Net Income
330

 
356

 
743

 
734

Dividends on Preferred and Preference Stock
5

 
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.

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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, total
666

 
634

Deferred income taxes
260

 
267

Allowance for equity funds used during construction
(27
)
 
(23
)
Pension, postretirement, and other employee benefits
(4
)
 
(14
)
Other, net
43

 
(12
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
(163
)
 
(4
)
-Fossil fuel stock
34

 
18

-Other current assets
(58
)
 
(46
)
-Accounts payable
(125
)
 
(113
)
-Accrued taxes
159

 
207

-Accrued compensation
(48
)
 
(22
)
-Retail fuel cost over recovery
(76
)
 
(104
)
-Other current liabilities
7

 
19

Net cash provided from operating activities
1,411

 
1,541

Investing Activities:
 
 
 
Property additions
(1,211
)
 
(947
)
Nuclear decommissioning trust fund purchases
(174
)
 
(275
)
Nuclear decommissioning trust fund sales
174

 
275

Cost of removal, net of salvage
(82
)
 
(70
)
Change in construction payables
105

 
(37
)
Other investing activities
(29
)
 
(28
)
Net cash used for investing activities
(1,217
)
 
(1,082
)
Financing Activities:
 
 
 
Proceeds —
 
 
 
Senior notes
550

 
400

Capital contributions from parent company
337

 
253

Preferred stock
250

 

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 activities
339

 
(97
)
Net Change in Cash and Cash Equivalents
533

 
362

Cash and Cash Equivalents at Beginning of Period
420

 
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, net
146

 
(70
)
Noncash transactions — Accrued property additions at end of period
189

 
84

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

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ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At 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.


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



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 pricing
85

 
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 – affiliates
14

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



Details of Alabama Power's generation and purchased power were as follows:
 
Third Quarter 2017
 
Third Quarter 2016
 
Year-to-Date 2017

Year-to-Date 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) —
 
 
 
 
 
 
 
Coal
52
 
59
 
49
 
51
Nuclear
24
 
22
 
25
 
24
Gas
19
 
18
 
20
 
19
Hydro
5
 
1
 
6
 
6
Cost of fuel, generated (in cents per net KWH) 
 
 
 
 
 
 
 
Coal
2.61
 
2.73
 
2.61
 
2.80
Nuclear
0.75
 
0.77
 
0.75
 
0.78
Gas
2.72
 
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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



effect adjustment, is not expected to have a material impact on either the timing or 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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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the September 2017 issuance, 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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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At September 30, 2017, 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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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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



In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2017, 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.

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GEORGIA POWER COMPANY

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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-affiliates
45

 
49

 
124

 
131

Wholesale revenues, affiliates
6

 
9

 
23

 
24

Other revenues
93

 
100

 
284

 
302

Total operating revenues
2,546

 
2,698

 
6,426

 
6,621

Operating Expenses:
 
 
 
 
 
 
 
Fuel
482

 
575

 
1,297

 
1,390

Purchased power, non-affiliates
119

 
102

 
310

 
277

Purchased power, affiliates
161

 
142

 
470

 
392

Other operations and maintenance
413

 
496

 
1,194

 
1,393

Depreciation and amortization
225

 
215

 
669

 
639

Taxes other than income taxes
112

 
114

 
311

 
311

Total operating expenses
1,512

 
1,644

 
4,251

 
4,402

Operating Income
1,034

 
1,054

 
2,175

 
2,219

Other Income and (Expense):
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(105
)
 
(98
)
 
(310
)
 
(290
)
Other income (expense), net
5

 
11

 
41

 
35

Total other income and (expense)
(100
)
 
(87
)
 
(269
)
 
(255
)
Earnings Before Income Taxes
934

 
967

 
1,906

 
1,964

Income taxes
350

 
363

 
705

 
734

Net Income
584

 
604

 
1,201

 
1,230

Dividends on Preferred and Preference Stock
4

 
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.

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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, total
821

 
794

Deferred income taxes
328

 
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 activities
1,480

 
2,266

Investing Activities:
 
 
 
Property additions
(1,907
)
 
(1,566
)
Nuclear decommissioning trust fund purchases
(411
)
 
(563
)
Nuclear decommissioning trust fund sales
406

 
558

Cost of removal, net of salvage
(54
)
 
(45
)
Change in construction payables, net of joint owner portion
180

 
(139
)
Payments pursuant to LTSAs
(59
)
 
(27
)
Sale of property
63

 
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 company
412

 
294

Senior notes
1,350

 
650

FFB loan

 
300

Short-term borrowings
700

 

Other long-term debt
370

 

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 activities
617

 
(528
)
Net Change in Cash and Cash Equivalents
263

 
(20
)
Cash and Cash Equivalents at Beginning of Period
3

 
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, net
369

 
188

Noncash transactions — Accrued property additions at end of period
470

 
226

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

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GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At 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.


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


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 pricing
41

 
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-affiliates
17

 
16.7

 
33

 
11.9

Purchased power – affiliates
19

 
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) —
 
 
 
 
 
 
 
Coal
35
 
44
 
33
 
37
Nuclear
23
 
22
 
24
 
23
Gas
41
 
34
 
41
 
38
Hydro
1
 
 
2
 
2
Cost of fuel, generated (in cents per net KWH) 
 
 
 
 
 
 
 
Coal
3.08
 
3.16
 
3.17
 
3.32
Nuclear
0.84
 
0.85
 
0.84
 
0.85
Gas
2.63
 
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, 2017
4.6

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 tax
1.5

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 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 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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The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Georgia Power regularly reviews its business to transform and modernize. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and ongoing efforts to increase overall operating efficiencies, Georgia Power initiated the closure of its remaining payment offices and an employee attrition plan affecting approximately 300 positions. Charges associated with these activities did not have a material impact on Georgia Power's results of operations, financial position, or cash flows. The efficiencies gained are expected to place downward pressure on operating costs in 2018.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and 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 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 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 September 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 $1.48 billion for the first nine months of 2017 compared to $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 $1.83 billion for the first nine months of 2017 compared to $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 $617 million for the first nine months of 2017 compared to $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 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 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 nine months of 2017 include increases of $1.2 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, $1.2 billion in long-term debt primarily due to issuances of senior notes and junior subordinated notes, $423 million in accounts payable, other primarily due to charges for restoration costs related to Hurricane Irma and liabilities for the removal of subcontractor liens related to the EPC Contractor's bankruptcy, and $423 million in paid-in capital primarily due to capital contributions received from Southern Company. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Recovery" and " – 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 September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersNuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
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 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 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 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

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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, 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.
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 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 September 30, 2017, Georgia Power's current liabilities exceeded current assets by $698 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt ($261 million at September 30, 2017) and the periodic use of short-term debt as a funding source ($400 million at September 30, 2017), as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans, 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 September 30, 2017, Georgia Power had approximately $266 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at September 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.
This bank credit arrangement, as well as Georgia Power's term loan arrangements, contains a covenant that limits debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2017, 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 September 30, 2017 was approximately $550 million as compared to $868 million at December 31, 2016. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS


credit arrangement. In addition, at September 30, 2017, Georgia Power had $509 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
 
 
Short-term Debt at September 30, 2017
 
Short-term Debt During the Period(*)
 
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
 
(in millions)
 
 
 
(in millions)
 
 
 
(in millions)
Commercial paper
 
$

 
%
 
$
109

 
1.5
%
 
$
428

Short-term bank debt
 
400

 
2.0
%
 
568

 
2.0
%
 
800

Total
 
$
400

 
2.0
%
 
$
677

 
2.0
%
 
 
(*)
Average and maximum amounts are based upon daily balances during the three-month period ended September 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 September 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.
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 Baa3
$
87

Below BBB- and/or Baa3
$
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 remarketed these bonds to the 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, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
Also in August 2017, Georgia Power purchased and held $38 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.

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GULF 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
$
375

 
$
377

 
$
972

 
$
978

Wholesale revenues, non-affiliates
14

 
17

 
44

 
48

Wholesale revenues, affiliates
28

 
23

 
75

 
59

Other revenues
20

 
19

 
53

 
51

Total operating revenues
437

 
436

 
1,144

 
1,136

Operating Expenses:
 
 
 
 
 
 
 
Fuel
127

 
141

 
323

 
342

Purchased power, non-affiliates
37

 
33

 
104

 
95

Purchased power, affiliates
2

 
3

 
13

 
9

Other operations and maintenance
81

 
86

 
252

 
239

Depreciation and amortization
42

 
49

 
95

 
129

Taxes other than income taxes
33

 
34

 
88

 
93

Loss on Plant Scherer Unit 3

 

 
33

 

Total operating expenses
322

 
346

 
908

 
907

Operating Income
115

 
90

 
236

 
229

Other Income and (Expense):
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(13
)
 
(11
)
 
(37
)
 
(36
)
Other income (expense), net
1

 
(2
)
 

 
(4
)
Total other income and (expense)
(12
)
 
(13
)
 
(37
)
 
(40
)
Earnings Before Income Taxes
103

 
77

 
199

 
189

Income taxes
40

 
30

 
78

 
74

Net Income
63

 
47

 
121

 
115

Dividends on Preference Stock

 
2

 
4

 
7

Net Income After Dividends on Preference Stock
$
63

 
$
45

 
$
117

 
$
108

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
$
63

 
$
47

 
$
121

 
$
115

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Changes in fair value, net of tax of $-, $-, $(1), and $(3), respectively

 

 
(1
)
 
(4
)
Total other comprehensive income (loss)

 

 
(1
)
 
(4
)
Comprehensive Income
$
63

 
$
47

 
$
120

 
$
111

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
For the Nine Months Ended September 30,
 
2017
 
2016
 
(in millions)
Operating Activities:
 
 
 
Net income
$
121

 
$
115

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
100

 
134

Deferred income taxes
57

 
15

Loss on Plant Scherer Unit 3
33

 

Other, net
(5
)
 
(2
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
(65
)
 
(9
)
-Fossil fuel stock
7

 
49

-Other current assets
11

 
3

-Accrued taxes
21

 
40

-Accrued compensation
(10
)
 
(5
)
-Over recovered regulatory clause revenues
(8
)
 
26

-Other current liabilities
10

 
8

Net cash provided from operating activities
272

 
374

Investing Activities:
 
 
 
Property additions
(142
)
 
(106
)
Cost of removal, net of salvage
(16
)
 
(8
)
Change in construction payables
(9
)
 
(7
)
Other investing activities
(6
)
 
(6
)
Net cash used for investing activities
(173
)
 
(127
)
Financing Activities:
 
 
 
Decrease in notes payable, net
(268
)
 
(42
)
Proceeds —
 
 
 
Common stock issued to parent
175

 

Capital contributions from parent company
7

 
10

Senior notes
300

 

Redemptions —
 
 
 
Preference stock
(150
)
 

Senior notes
(85
)
 
(125
)
Payment of common stock dividends
(94
)
 
(90
)
Other financing activities
(3
)
 
(5
)
Net cash used for financing activities
(118
)
 
(252
)
Net Change in Cash and Cash Equivalents
(19
)
 
(5
)
Cash and Cash Equivalents at Beginning of Period
56

 
74

Cash and Cash Equivalents at End of Period
$
37

 
$
69

Supplemental Cash Flow Information:
 
 
 
Cash paid during the period for —
 
 
 
Interest (net of $- and $- capitalized for 2017 and 2016, respectively)
$
24

 
$
29

Income taxes, net
19

 
14

Noncash transactions — Accrued property additions at end of period
25

 
13

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

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CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30, 2017
 
At December 31, 2016
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
37

 
$
56

Receivables —
 
 
 
 
Customer accounts receivable
 
96

 
72

Unbilled revenues
 
68

 
55

Under recovered regulatory clause revenues
 
15

 
17

Income taxes receivable, current
 
15

 

Other accounts and notes receivable
 
12

 
6

Affiliated
 
13

 
17

Accumulated provision for uncollectible accounts
 
(1
)
 
(1
)
Fossil fuel stock
 
64

 
71

Materials and supplies
 
58

 
55

Other regulatory assets, current
 
55

 
44

Other current assets
 
15

 
30

Total current assets
 
447

 
422

Property, Plant, and Equipment:
 
 
 
 
In service
 
5,181

 
5,140

Less: Accumulated provision for depreciation
 
1,457

 
1,382

Plant in service, net of depreciation
 
3,724

 
3,758

Construction work in progress
 
75

 
51

Total property, plant, and equipment
 
3,799

 
3,809

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
56

 
58

Other regulatory assets, deferred
 
499

 
512

Other deferred charges and assets
 
22

 
21

Total deferred charges and other assets
 
577

 
591

Total Assets
 
$
4,823

 
$
4,822

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


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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
 
$
7

 
$
87

Notes payable
 

 
268

Accounts payable —
 
 
 
 
Affiliated
 
46

 
59

Other
 
55

 
54

Customer deposits
 
35

 
35

Accrued taxes
 
41

 
20

Accrued interest
 
20

 
8

Accrued compensation
 
30

 
40

Deferred capacity expense, current
 
22

 
22

Other regulatory liabilities, current
 
1

 
16

Other current liabilities
 
37

 
40

Total current liabilities
 
294

 
649

Long-term Debt
 
1,285

 
987

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
1,003

 
948

Employee benefit obligations
 
90

 
96

Deferred capacity expense
 
103

 
119

Asset retirement obligations, deferred
 
125

 
120

Other cost of removal obligations
 
218

 
249

Other regulatory liabilities, deferred
 
45

 
47

Other deferred credits and liabilities
 
71

 
71

Total deferred credits and other liabilities
 
1,655

 
1,650

Total Liabilities
 
3,234

 
3,286

Preference Stock
 

 
147

Common Stockholder's Equity:
 
 
 
 
Common stock, without par value —
 
 
 
 
Authorized — 20,000,000 shares
 
 
 
 
Outstanding — September 30, 2017: 7,392,717 shares
 
 
 
 
                    — December 31, 2016: 5,642,717 shares
 
678

 
503

Paid-in capital
 
600

 
589

Retained earnings
 
312

 
296

Accumulated other comprehensive income (loss)
 
(1
)
 
1

Total common stockholder's equity
 
1,589

 
1,389

Total Liabilities and Stockholder's Equity
 
$
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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2017 vs. THIRD 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. 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.
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
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 third quarter 2017 was $63 million compared to $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 $117 million compared to $108 million for the corresponding period in 2016. The increase 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. 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.
Retail Revenues
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(2)
 
(0.5)
 
$(6)
 
(0.6)
In the third quarter 2017, retail revenues were $375 million compared to $377 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $972 million compared to $978 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
 
Third Quarter 2017
 
Year-to-Date 2017
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail – prior year
$
377

 
 
 
$
978

 
 
Estimated change resulting from –
 
 
 
 
 
 
 
Rates and pricing
21

 
5.6

 
28

 
2.9

Sales growth
3

 
0.8

 
1

 
0.1

Weather
(9
)
 
(2.4
)
 
(14
)
 
(1.4
)
Fuel and other cost recovery
(17
)
 
(4.5
)
 
(21
)
 
(2.2
)
Retail – current year
$
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 third 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 increased slightly in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. For 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 slightly year-to-date 2017 as a result of lower customer usage primarily resulting from efficiency improvements in appliances and lighting, mostly offset by customer growth. KWH sales to industrial customers decreased 7.1% and 6.1% for the third quarter and year-to-date 2017, respectively, primarily due to changes in customers' operations and energy efficiency improvements.
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 lower fuel, purchased power capacity, and energy conservation recoverable costs, partially offset by higher environmental recoverable costs. Fuel and other cost recovery

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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
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 third quarter 2017, wholesale revenues from sales to affiliates were $28 million compared to $23 million for the corresponding period in 2016. The increase was primarily due to a 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 the availability of lower-cost Gulf Power generation resources.

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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
$
(14
)
 
(9.9
)
 
$
(19
)
 
(5.6
)
Purchased power – non-affiliates
4

 
12.1

 
9

 
9.5

Purchased power – affiliates
(1
)
 
(33.3
)
 
4

 
44.4

Total fuel and purchased power expenses
$
(11
)
 
 
 
$
(6
)
 
 
In the third quarter 2017, total fuel and purchased power expenses were $166 million compared to $177 million for the corresponding period in 2016. The decrease was primarily the result of a $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 a $12 million net increase related to the higher average cost of fuel and purchased 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.
Details of Gulf Power's generation and purchased power were as follows:
 
Third Quarter 2017
 
Third Quarter 2016
 
Year-to-Date 2017
 
Year-to-Date 2016
Total generation (in millions of KWHs)
2,780
 
2,775
 
7,000
 
6,654
Total purchased power (in millions of KWHs)
1,686
 
1,906
 
4,362
 
5,295
Sources of generation (percent) –
 
 
 
 
 
 
 
Coal
59
 
68
 
55
 
57
Gas
41
 
32
 
45
 
43
Cost of fuel, generated (in cents per net KWH) –
 
 
 
 
 
 
 
Coal
3.04
 
3.55
 
3.15
 
3.80
Gas
3.71
 
4.38
 
3.60
 
4.06
Average cost of fuel, generated (in cents per net KWH)
3.31
 
3.81
 
3.35
 
3.91
Average cost of purchased power (in cents per net KWH)(*)
4.32
 
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 third quarter 2017, fuel expense was $127 million compared to $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, partially offset by a 10.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
Purchased Power – Non-Affiliates
In the third quarter 2017, purchased power expense from non-affiliates was $37 million compared to $33 million for the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $104 million compared to $95 million for the corresponding period in 2016. These increases were primarily due to increases of 16.3% and 35.9% for the third quarter and year-to-date 2017, respectively, in the average cost per KWH purchased, partially offset by decreases of 11.1% and 20.2% for the third quarter and year-to-date 2017, respectively, in the volume of KWHs purchased due to 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 third quarter 2017, purchased power expense from affiliates was $2 million compared to $3 million for the corresponding period in 2016. The decrease was primarily due to a 38.3% decrease in the average cost per KWH purchased primarily resulting from lower priced power pool resources and a 20.5% decrease in the volume of KWHs purchased due to lower territorial load.
For year-to-date 2017, purchased power expense from affiliates was $13 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a 13.2% increase in the volume of KWHs purchased due to more planned outages for Gulf Power generation resources and a 29.3% increase in the average cost per KWH purchased primarily due to increased natural gas prices.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(5)
 
(5.8)
 
$13
 
5.4
In the third quarter 2017, other operations and maintenance expenses were $81 million compared to $86 million for the corresponding period in 2016. The decrease was primarily due to lower employee compensation and benefits, including pension costs, and the suspension of the property damage reserve accrual in accordance with the 2017 Rate Case Settlement Agreement.
For year-to-date 2017, other operations and maintenance expenses were $252 million compared to $239 million for the corresponding period in 2016. The increase was primarily due to higher expenses at generation facilities associated with routine and planned maintenance.
See Note (A) to the Condensed Financial Statements under "Property Damage Reserve" herein for additional information regarding Gulf Power's property damage reserve accrual suspension and Note (B) to the Condensed Financial Statements under "Regulatory MattersGulf PowerRetail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.

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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)
$(7)
 
(14.3)
 
$(34)
 
(26.4)
In the third quarter 2017, depreciation and amortization was $42 million compared to $49 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $95 million compared to $129 million for the corresponding period in 2016. These decreases were primarily due to changes 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 third 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 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

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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 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 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 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.
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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Gulf Power's) and Southern Power's June 30, 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. 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

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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 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.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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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.
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 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. 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 September 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 $272 million for the first nine months of 2017 compared to $374 million for the corresponding period in 2016. The $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. Net cash used for investing activities totaled $173 million in the first nine months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $118 million for the first nine 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 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 nine 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. 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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GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2018 to fund maturities of long-term debt. 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.
At September 30, 2017, Gulf Power had approximately $37 million 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
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 September 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2017 was approximately $82 million. In addition, at September 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 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 September 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.
Credit Rating Risk
At September 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, and energy price risk management.
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 Baa3
$
167

Below BBB- and/or Baa3
$
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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GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the third 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 until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.
For additional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.
Financing Activities
In January 2017, Gulf Power issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including Gulf Power's continuous construction program.
In March 2017, Gulf Power 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 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.

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MISSISSIPPI POWER COMPANY

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MISSISSIPPI 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
$
243

 
$
263

 
$
665

 
$
652

Wholesale revenues, non-affiliates
72

 
78

 
196

 
198

Wholesale revenues, affiliates
21

 
7

 
40

 
23

Other revenues
5

 
4

 
14

 
12

Total operating revenues
341

 
352

 
915

 
885

Operating Expenses:
 
 
 
 
 
 
 
Fuel
120

 
112

 
301

 
268

Purchased power, non-affiliates
4

 
3

 
7

 
4

Purchased power, affiliates
2

 
5

 
13

 
14

Other operations and maintenance
66

 
74

 
206

 
211

Depreciation and amortization
39

 
30

 
120

 
114

Taxes other than income taxes
25

 
31

 
77

 
81

Estimated loss on Kemper IGCC
34

 
88

 
3,155

 
222

Total operating expenses
290

 
343

 
3,879

 
914

Operating Income (Loss)
51

 
9

 
(2,964
)
 
(29
)
Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
1

 
31

 
72

 
90

Interest expense, net of amounts capitalized
13

 
(15
)
 
(23
)
 
(46
)
Other income (expense), net
(1
)
 
(1
)
 
(3
)
 
(4
)
Total other income and (expense)
13

 
15

 
46

 
40

Earnings (Loss) Before Income Taxes
64

 
24

 
(2,918
)
 
11

Income taxes (benefit)
24

 
(2
)
 
(885
)
 
(29
)
Net Income (Loss)
40

 
26

 
(2,033
)
 
40

Dividends on Preferred Stock

 

 
1

 
1

Net Income (Loss) After Dividends on Preferred Stock
$
40

 
$
26

 
$
(2,034
)
 
$
39

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 (Loss)
$
40

 
$
26

 
$
(2,033
)
 
$
40

Other comprehensive income (loss)

 

 

 

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

 

Comprehensive Income (Loss)
$
39

 
$
26

 
$
(2,032
)
 
$
40

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

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MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Nine Months Ended September 30,
 
2017
 
2016
 
(in millions)
Operating Activities:
 
 
 
Net income (loss)
$
(2,033
)
 
$
40

Adjustments to reconcile net income (loss) to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
144

 
115

Deferred income taxes
(1,159
)
 
34

Allowance for equity funds used during construction
(72
)
 
(90
)
Estimated loss on Kemper IGCC
3,148

 
222

Other, net
(26
)
 
(1
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
438

 
3

-Fossil fuel stock
21

 
8

-Other current assets
(9
)
 
34

-Accounts payable
(21
)
 
5

-Accrued taxes
20

 
96

-Accrued compensation
(12
)
 
(5
)
-Over recovered regulatory clause revenues
(47
)
 
(20
)
-Customer liability associated with Kemper refunds

 
(73
)
-Other current liabilities
(31
)
 
5

Net cash provided from operating activities
361

 
373

Investing Activities:
 
 
 
Property additions
(411
)
 
(592
)
Construction payables
(47
)
 
(25
)
Government grant proceeds

 
137

Other investing activities
(25
)
 
(29
)
Net cash used for investing activities
(483
)
 
(509
)
Financing Activities:
 
 
 
Decrease in notes payable, net
(23
)
 

Proceeds —
 
 
 
Capital contributions from parent company
1,002

 
227

Long-term debt to parent company
40

 
200

Other long-term debt

 
900

Short-term borrowings
113

 

Redemptions —
 
 
 
Short-term borrowings
(109
)
 
(475
)
Long-term debt to parent company
(591
)
 
(225
)
Other long-term debt
(300
)
 
(425
)
Other financing activities
(3
)
 
(5
)
Net cash provided from financing activities
129

 
197

Net Change in Cash and Cash Equivalents
7

 
61

Cash and Cash Equivalents at Beginning of Period
224

 
98

Cash and Cash Equivalents at End of Period
$
231

 
$
159

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (paid $73 and $72, net of $28 and $36 capitalized for 2017
and 2016, respectively)
$
45

 
$
36

Income taxes, net
(209
)
 
(231
)
Noncash transactions — Accrued property additions at end of period
32

 
80

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

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MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30, 2017
 
At December 31, 2016
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
231

 
$
224

Receivables —
 
 
 
 
Customer accounts receivable
 
38

 
29

Unbilled revenues
 
41

 
42

Income taxes receivable, current
 
102

 
544

Other accounts and notes receivable
 
15

 
14

Affiliated
 
15

 
15

Fossil fuel stock
 
20

 
100

Materials and supplies
 
45

 
76

Other regulatory assets, current
 
113

 
115

Other current assets
 
8

 
8

Total current assets
 
628

 
1,167

Property, Plant, and Equipment:
 
 
 
 
In service
 
4,836

 
4,865

Less: Accumulated provision for depreciation
 
1,312

 
1,289

Plant in service, net of depreciation
 
3,524

 
3,576

Construction work in progress
 
75

 
2,545

Total property, plant, and equipment
 
3,599

 
6,121

Other Property and Investments
 
28

 
12

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
62

 
361

Other regulatory assets, deferred
 
436

 
518

Accumulated deferred income taxes
 
279

 

Other deferred charges and assets
 
23

 
56

Total deferred charges and other assets
 
800

 
935

Total Assets
 
$
5,055

 
$
8,235

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


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MISSISSIPPI 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 —
 
 
 
 
Parent
 
$

 
$
551

Other
 
1,028

 
78

Notes payable
 
4

 
23

Accounts payable —
 
 
 
 
Affiliated
 
56

 
62

Other
 
82

 
135

Customer deposits
 
16

 
16

Accrued taxes
 
78

 
99

Unrecognized tax benefits
 
2

 
383

Accrued interest
 
16

 
46

Accrued compensation
 
29

 
42

Asset retirement obligations, current
 
15

 
32

Over recovered fuel clause liabilities
 
4

 
51

Other current liabilities
 
67

 
20

Total current liabilities
 
1,397

 
1,538

Long-term Debt
 
1,167

 
2,424

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 

 
756

Employee benefit obligations
 
109

 
115

Asset retirement obligations, deferred
 
150

 
146

Other cost of removal obligations
 
175

 
170

Other regulatory liabilities, deferred
 
87

 
84

Other deferred credits and liabilities
 
23

 
26

Total deferred credits and other liabilities
 
544

 
1,297

Total Liabilities
 
3,108

 
5,259

Redeemable Preferred Stock
 
33

 
33

Common Stockholder's Equity:
 
 
 
 
Common stock, without par value —
 
 
 
 
Authorized — 1,130,000 shares
 
 
 
 
Outstanding — 1,121,000 shares
 
38

 
38

Paid-in capital
 
4,529

 
3,525

Accumulated deficit
 
(2,650
)
 
(616
)
Accumulated other comprehensive loss
 
(3
)
 
(4
)
Total common stockholder's equity
 
1,914

 
2,943

Total Liabilities and Stockholder's Equity
 
$
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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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2017 vs. THIRD 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 (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) 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 initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue 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

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

settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject 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.
Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

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

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" herein.
In addition to the rate recovery of the Kemper County energy facility, Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income (Loss)
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$14
 
53.8
 
$(2,073)
 
N/M
N/M - Not meaningful
Mississippi Power's net income after dividends on preferred stock for the third 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 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 $2.03 billion compared to net income of $39 million for the corresponding period in 2016. The decrease in net income was related to higher pre-tax charges associated with the Kemper IGCC.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

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Retail Revenues
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(20)
 
(7.6)
 
$13
 
2.0
In the third quarter 2017, retail revenues were $243 million compared to $263 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $665 million compared to $652 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
 
Third Quarter 2017
 
Year-to-Date 2017
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail – prior year
$
263

 
 
 
$
652

 
 
Estimated change resulting from –
 
 
 
 
 
 
 
Rates and pricing
(10
)
 
(3.8
)
 
9

 
1.4

Sales growth
1

 
0.4

 
4

 
0.6

Weather
(9
)
 
(3.4
)
 
(16
)
 
(2.5
)
Fuel and other cost recovery
(2
)
 
(0.8
)
 
16

 
2.5

Retail – current year
$
243

 
(7.6
)%
 
$
665

 
2.0
 %
Revenues associated with changes in rates and pricing decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily due to recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.
Revenues associated with changes in rates and pricing increased in year-to-date 2017 when compared to the corresponding period 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 increased slightly for the third quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 2.9% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 2.4% primarily due to an unplanned outage by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.
Revenues attributable to changes in sales increased slightly for year-to-date 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 0.8% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.7% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 1.1% primarily due to unplanned outages by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.
Fuel and other cost recovery revenues decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased

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for year-to-date 2017 when compared to the corresponding period 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 – Affiliates
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$14
 
N/M
 
$17
 
73.9
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 third quarter 2017, wholesale revenues from sales to affiliates were $21 million compared to $7 million for the corresponding period in 2016. The increase was due to a $13 million increase in KWH sales as a result of supporting Southern Company system transmission reliability and a $1 million increase primarily due to higher natural gas prices.
For year-to-date 2017, wholesale revenues from sales to affiliates were $40 million compared to $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
 
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
$
8

 
7.1
 
$
33

 
12.3
Purchased power – non-affiliates
1

 
33.3
 
3

 
75.0
Purchased power – affiliates
(3
)
 
(60.0)
 
(1
)
 
(7.1)
Total fuel and purchased power expenses
$
6

 
 
 
$
35

 
 
In the third quarter 2017, total fuel and purchased power expenses were $126 million compared to $120 million for the corresponding period in 2016. The increase was due to a $6 million increase in the volume of KWHs generated and purchased.
For year-to-date 2017, total fuel and purchased power expenses were $321 million compared to $286 million for the corresponding period in 2016. The increase was primarily due to a $42 million increase in the average cost of natural gas and purchased power, partially offset by a $4 million decrease in coal prices and a $3 million decrease in the volume of KWHs generated and purchased.
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:
 
Third Quarter 2017
 
Third Quarter 2016
 
Year-to-Date 2017
 
Year-to-Date 2016
Total generation (in millions of KWHs)
4,453
 
4,255
 
11,542
 
11,570
Total purchased power (in millions of KWHs)(*)
164
 
288
 
527
 
877
Sources of generation (percent) –
 
 
 
 
 
 
 
Coal
8
 
10
 
8
 
9
Gas
92
 
90
 
92
 
91
Cost of fuel, generated (in cents per net KWH) 
 
 
 
 
 
 
 
Coal
3.80
 
4.02
 
3.60
 
4.09
Gas
2.77
 
2.64
 
2.72
 
2.34
Average cost of fuel, generated (in cents per net KWH)
2.86
 
2.79
 
2.80
 
2.50
Average cost of purchased power (in cents per net KWH)(*)
3.74
 
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 third quarter 2017, total fuel expense was $120 million compared to $112 million for the corresponding period in 2016. The increase was due to a 2.5% increase in the average cost of fuel per KWH generated, primarily due to a 4.5% higher cost of natural gas, and a 5.4% increase in the volume of KWHs generated.
For year-to-date 2017, total fuel expense was $301 million compared to $268 million for the corresponding period in 2016. The increase was due to a 12.0% increase in the average cost of fuel per KWH generated primarily due to a 16.2% higher cost of natural gas.
Purchased Power
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(8)
 
(10.8)
 
$(5)
 
(2.4)
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 $206 million compared to $211 million for the corresponding period in 2016. The decrease 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.
Depreciation and Amortization
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$9
 
30.0
 
$6
 
5.3
In the third quarter 2017, depreciation and amortization was $39 million compared to $30 million for the corresponding period in 2016. The increase was primarily related to $6 million in amortization and deferrals associated with regulatory 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
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(54)
 
(61.4)
 
$2,933
 
N/M
N/M - Not meaningful
Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate 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 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
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(30)
 
(96.8)
 
$(18)
 
(20.0)
In the third quarter 2017, AFUDC equity was $1 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $72 million compared to $90 million for the corresponding period in 2016. The decreases resulted from the Kemper IGCC project suspension in June 2017.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(28)
 
N/M
 
$(23)
 
50.0
N/M - Not meaningful
In the third quarter 2017, interest expense, net of amounts capitalized was $(13) million compared to $15 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to research and experimental (R&E) deductions. Also contributing to the decrease was a $4 million decrease in interest related to long-term debt. These decreases were partially offset by an $11 million reduction in interest capitalized following suspension of the Kemper IGCC construction.
For year-to-date 2017, interest expense, net of amounts capitalized was $23 million compared to $46 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to R&E deductions. Also contributing to the decrease was a $2 million decrease in interest related to short-term debt and a $1 million decrease in interest related to long-term debt. These decreases were partially offset by an $8 million reduction in interest capitalized following suspension of the Kemper IGCC construction and the amortization of $7 million in interest deferrals in accordance with the In-Service Asset Rate Order.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" 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)
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 third quarter 2017, income taxes were $24 million compared to an income tax benefit of $2 million for the corresponding period in 2016. For year-to-date 2017, income tax benefit was $885 million compared to $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 the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The new agreements are not expected to have a material impact on Mississippi Power's earnings; however, the co-generation assets located at the refinery are expected to be accounted for as a sales-type lease in accordance with the new lease accounting rules that become effective in 2019. These assets are also subject to a security interest granted to Chevron. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Mississippi Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
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 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 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.
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 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.
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 related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's June 30, 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
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates. 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 three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
On 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 these matters cannot be determined at this time.
Energy Efficiency
On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 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 September 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $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 and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured

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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. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate 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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Rate Recovery of Kemper IGCC Costs
Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
Kemper IGCC Settlement Docket
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.
As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which

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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 Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual

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

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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 Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note 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 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 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 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
All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Mississippi Power recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.

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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.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
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 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 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 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 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 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 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 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 nine months ended September 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 September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs.
Net cash provided from operating activities totaled $361 million for the first nine months of 2017, a decrease of $12 million as compared to the corresponding period in 2016. The decrease in cash provided from operating activities is primarily due to deferred income taxes related to the Kemper IGCC, partially offset by the timing of payments received from affiliates and customers and 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 $483 million for the first nine months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $129 million for the first nine months of 2017 primarily due to capital contributions from Southern Company, partially offset by redemptions of long-term 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 nine 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 CWIP, $756 million in accumulated deferred income taxes, and $299 million in deferred charges related to income taxes. All of these changes primarily resulted 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 Coal Gasification Combined Cycle" and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.
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,

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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 September 30, 2018 to fund maturities of long-term debt and $4 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities 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 Coal Gasification Combined Cycle" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $582 million for 2017, $203 million for 2018, $177 million for 2019, $204 million for 2020, $199 million for 2021, and $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 September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as

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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 Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
At September 30, 2017, Mississippi Power had approximately $231 million 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
2017
 
Total
 
Unused
 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)
$
100

 
$
100

 
$
100

 
$

 
$

 
$

 
$
100

See Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (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 September 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 September 30, 2017 was approximately $40 million. In addition, at September 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 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 September 30, 2017.

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Credit Rating Risk
At September 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 sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2017, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $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.


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SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED 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:
 
 
 
 
 
 
 
Wholesale revenues, non-affiliates
$
510

 
$
387

 
$
1,293

 
$
866

Wholesale revenues, affiliates
105

 
110

 
295

 
313

Other revenues
3

 
3

 
9

 
10

Total operating revenues
618

 
500

 
1,597

 
1,189

Operating Expenses:
 
 
 
 
 
 
 
Fuel
189

 
154

 
460

 
341

Purchased power, non-affiliates
36

 
25

 
90

 
60

Purchased power, affiliates
7

 
8

 
23

 
16

Other operations and maintenance
83

 
81

 
272

 
246

Depreciation and amortization
131

 
93

 
379

 
247

Taxes other than income taxes
13

 
5

 
37

 
17

Total operating expenses
459


366

 
1,261

 
927

Operating Income
159

 
134

 
336

 
262

Other Income and (Expense):
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(47
)
 
(35
)
 
(144
)
 
(78
)
Other income (expense), net
3

 
2

 
3

 
3

Total other income and (expense)
(44
)
 
(33
)
 
(141
)
 
(75
)
Earnings Before Income Taxes
115

 
101

 
195

 
187

Income taxes (benefit)
(39
)
 
(102
)
 
(129
)
 
(167
)
Net Income
154

 
203

 
324

 
354

Less: Net income attributable to noncontrolling interests
30

 
27

 
48

 
39

Net Income Attributable to Southern Power
$
124

 
$
176

 
$
276

 
$
315

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in millions)
 
(in millions)
Net Income
$
154

 
$
203

 
$
324

 
$
354

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Changes in fair value, net of tax of
$15, $14, $35, and $(1), respectively
25

 
23

 
58

 
(1
)
Reclassification adjustment for amounts included in net income,
net of tax of $(12), $(1), $(42), and $7, respectively
(20
)
 
(1
)
 
(68
)
 
13

Total other comprehensive income (loss)
5

 
22

 
(10
)
 
12

Comprehensive Income
159

 
225

 
314

 
366

Less: Comprehensive income attributable to noncontrolling interests
30

 
27

 
48

 
39

Comprehensive Income Attributable to Southern Power
$
129

 
$
198

 
$
266

 
$
327

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
For the Nine Months Ended September 30,
 
2017
 
2016
 
(in millions)
Operating Activities:
 
 
 
Net income
$
324

 
$
354

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
404

 
262

Deferred income taxes
240

 
(668
)
Amortization of investment tax credits
(42
)
 
(25
)
Collateral deposits
(1
)
 
(80
)
Income taxes receivable, non-current
(42
)
 

Other, net
(2
)
 
19

Changes in certain current assets and liabilities —
 
 
 
-Receivables
(77
)
 
(82
)
-Other current assets
38

 
(15
)
-Accounts payable
(31
)
 
7

-Accrued taxes
79

 
483

-Other current liabilities
5

 
14

Net cash provided from operating activities
895

 
269

Investing Activities:
 
 
 
Business acquisitions
(1,032
)
 
(1,134
)
Property additions
(218
)
 
(1,702
)
Change in construction payables
(166
)
 
(69
)
Payments pursuant to LTSAs
(99
)
 
(58
)
Investment in restricted cash
(16
)
 
(750
)
Distribution of restricted cash
33

 
746

Other investing activities
7

 
(41
)
Net cash used for investing activities
(1,491
)
 
(3,008
)
Financing Activities:
 
 
 
Increase (decrease) in notes payable, net
(89
)
 
692

Proceeds —
 
 
 
Senior notes

 
1,531

Capital contributions from parent company

 
800

Other long-term debt
43

 
63

Redemptions — Other long-term debt
(4
)
 
(84
)
Distributions to noncontrolling interests
(89
)
 
(22
)
Capital contributions from noncontrolling interests
79

 
367

Purchase of membership interests from noncontrolling interests

 
(129
)
Payment of common stock dividends
(238
)
 
(204
)
Other financing activities
(27
)
 
(14
)
Net cash provided from (used for) financing activities
(325
)
 
3,000

Net Change in Cash and Cash Equivalents
(921
)
 
261

Cash and Cash Equivalents at Beginning of Period
1,099

 
830

Cash and Cash Equivalents at End of Period
$
178

 
$
1,091

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively)
$
144

 
$
49

Income taxes, net
(343
)
 
71

Noncash transactions — Accrued property additions at end of period
16

 
210

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30, 2017
 
At December 31, 2016
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
178

 
$
1,099

Receivables —
 
 
 
 
Customer accounts receivable
 
148

 
102

Other
 
61

 
34

Affiliated
 
74

 
57

Fossil fuel stock
 
15

 
15

Materials and supplies
 
351

 
337

Prepaid income taxes
 
51

 
74

Other current assets
 
26

 
39

Total current assets
 
904

 
1,757

Property, Plant, and Equipment:
 
 
 
 
In service
 
13,734

 
12,728

Less: Accumulated provision for depreciation
 
1,823

 
1,484

Plant in service, net of depreciation
 
11,911

 
11,244

Construction work in progress
 
425

 
398

Total property, plant, and equipment
 
12,336

 
11,642

Other Property and Investments:
 
 
 
 
Intangible assets, net of amortization of $41 and $22
at September 30, 2017 and December 31, 2016, respectively
 
417

 
436

Total other property and investments
 
417

 
436

Deferred Charges and Other Assets:
 
 
 
 
Prepaid LTSAs
 
77

 
101

Accumulated deferred income taxes
 
400

 
594

Income taxes receivable, non-current
 
53

 
11

Other deferred charges and assets — affiliated
 
6

 
13

Other deferred charges and assets — non-affiliated
 
455

 
615

Total deferred charges and other assets
 
991

 
1,334

Total Assets
 
$
14,648

 
$
15,169

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholders' Equity
 
At September 30, 2017
 
At December 31, 2016
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
864

 
$
560

Notes payable
 
120

 
209

Accounts payable —
 
 
 
 
Affiliated
 
93

 
88

Other
 
84

 
278

Accrued taxes —
 
 
 
 
Accrued income taxes
 
101

 
148

Other accrued taxes
 
30

 
7

Accrued interest
 
36

 
36

Acquisitions payable
 

 
461

Contingent consideration
 
15

 
46

Other current liabilities
 
58

 
70

Total current liabilities
 
1,401

 
1,903

Long-term Debt
 
4,946

 
5,068

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
191

 
152

Accumulated deferred ITCs
 
1,900

 
1,839

Asset retirement obligations
 
76

 
64

Other deferred credits and liabilities
 
232

 
304

Total deferred credits and other liabilities
 
2,399

 
2,359

Total Liabilities
 
8,746

 
9,330

Redeemable Noncontrolling Interests
 
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
 
3,661

 
3,671

Retained earnings
 
762

 
724

Accumulated other comprehensive income
 
25

 
35

Total common stockholder's equity
 
4,448

 
4,430

Noncontrolling interests
 
1,395

 
1,245

Total stockholders' equity
 
5,843

 
5,675

Total Liabilities and Stockholders' Equity
 
$
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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THIRD QUARTER 2017 vs. THIRD 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, 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 nine months ended September 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 development of its portfolio of wind projects, and continued expansion of the Mankato natural gas facility by 345 MWs of capacity. See FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional information.
Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.
At September 30, 2017, 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
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(52)
 
(29.5)
 
$(39)
 
(12.4)
Net income attributable to Southern Power for the third quarter 2017 was $124 million compared to $176 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits from solar ITCs and increased interest expense primarily due to a decrease in capitalized interest associated with completing construction of and placing in service solar facilities, partially offset by additional operating income related to new generating facilities.
Net income attributable to Southern Power for year-to-date 2017 was $276 million compared to $315 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits resulting from a reduction in solar ITCs, partially offset by an increase in wind PTCs, and increased interest expense from debt issuances to fund Southern Power's growth strategy and continuous construction program, partially offset by additional operating income from new generating facilities.
For additional information on new generating facilities placed in service during 2016 and 2017, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and

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"Construction Projects" of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.
Operating Revenues
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$118
 
23.6
 
$408
 
34.3
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 energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have a capacity charge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.
See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.
Details of Southern Power's operating revenues were as follows:
 
Third Quarter 2017
 
Third Quarter 2016
 
Year-to-Date 2017
 
Year-to-Date 2016
 
(in millions)
PPA capacity revenues
$
169

 
$
149

 
$
466

 
$
406

PPA energy revenues
299

 
247

 
765

 
532

Total PPA revenues
468

 
396

 
1,231

 
938

Non-PPA revenues
147

 
101

 
357

 
241

Other revenues
3

 
3

 
9

 
10

Total operating revenues
$
618

 
$
500

 
$
1,597

 
$
1,189


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In the third quarter 2017, total operating revenues were $618 million, reflecting a $118 million, or 24%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $20 million, or 13%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $52 million, or 21%, primarily due to a $55 million increase in sales from new solar and wind facilities, partially offset by a $3 million decrease in sales from natural gas PPAs due to a $24 million decrease in volume primarily due to the expiration of a PPA and reduced customer load, partially offset by a $21 million increase in the average cost of fuel.
Non-PPA revenues increased $46 million, or 46%, due to a $58 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, offset by a $12 million decrease in the price of energy in the wholesale markets.
For year-to-date 2017, total operating revenues were $1.6 billion, reflecting a $408 million, or 34%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenues increased $60 million, or 15%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.
PPA energy revenues increased $233 million, or 44%, primarily due to a $188 million increase in sales from new solar and wind facilities and a $35 million increase in sales from natural gas PPAs primarily due to a $69 million increase in the average cost of fuel, partially offset by a $34 million decrease in volume primarily due to the expiration of a PPA and reduced customer load.
Non-PPA revenues increased $116 million, or 48%, due to a $104 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $12 million increase in the price of energy in the wholesale markets.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:
 
Third Quarter 2017
Third Quarter 2016
 
Year-to-Date 2017
Year-to-Date 2016
 
(in billions of KWHs)
Generation
12.5
11.1
 
33.2
27.9
Purchased power
1.2
0.9
 
3.4
2.5
Total generation and purchased power
13.7
12.0
 
36.6
30.4
 
 
 
 
 
 
Total generation and purchased power, excluding solar, wind, and tolling agreements
7.2
6.7
 
17.8
17.7
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 Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
 
Third Quarter 2017
vs.
Third Quarter 2016
 
Year-to-Date 2017
vs.
Year-to-Date 2016
 
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
Fuel
$
35

 
22.7
 
$
119

 
34.9
Purchased power
10

 
30.3
 
37

 
48.7
Total fuel and purchased power expenses
$
45

 
 
 
$
156

 
 
In the third quarter 2017, total fuel and purchased power expenses increased $45 million, or 24.1%, compared to the corresponding period in 2016. Fuel expense increased $35 million primarily due to a $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 a $19 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $37 million due to a $28 million increase in the volume of KWHs purchased and a $9 million increase associated with the average cost of purchased power.
Other Operations and Maintenance Expenses
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$2
 
2.5
 
$26
 
10.6
In the third quarter 2017, other operations and maintenance expenses were $83 million compared to $81 million for the corresponding period in 2016. The increase was primarily due to a $13 million increase associated with new solar, wind, and gas facilities, partially offset by a $5 million decrease in scheduled outage maintenance expenses and a $5 million decrease in non-outage operations and maintenance expenses.
For year-to-date 2017, other operations and maintenance expenses were $272 million compared to $246 million for the corresponding period in 2016. The increase was primarily due to a $48 million increase associated with new solar, wind, and gas facilities and an $8 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $22 million decrease in scheduled outage maintenance expenses and an $8 million decrease in non-outage operations and maintenance expenses.

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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)
$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
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$12
 
34.3
 
$66
 
84.6
In the third quarter 2017, interest expense, net of amounts capitalized was $47 million compared to $35 million for the corresponding period in 2016. The increase was primarily due to an $8 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities and an increase of $3 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program.
For year-to-date 2017, interest expense, net of amounts capitalized was $144 million compared to $78 million for the corresponding period in 2016. The increase was primarily due to an increase of $39 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $25 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
Other Income (Expense), Net
Third Quarter 2017 vs. Third Quarter 2016
 
Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$1
 
50.0
 
$—
 
In the third quarter 2017, other income (expense), net was $3 million compared to $2 million for the corresponding period in 2016. Other income (expense), net was $3 million for both year-to-date 2017 and 2016. The changes include increases of $36 million and $152 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the third 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)
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 third quarter 2017, income tax benefit was $39 million compared to $102 million for the corresponding period in 2016. The decrease was primarily due to a $61 million decrease in income tax benefits from solar ITCs.
For year-to-date 2017, income tax benefit was $129 million compared to $167 million for the corresponding period in 2016. The decrease was primarily due to a $102 million decrease in income tax benefits from solar ITCs, partially offset by a $58 million increase in wind PTCs and a $4 million increase resulting from state apportionment rate 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 and PTCs.
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 the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings.
Other factors that could influence future earnings include weather, demand, 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 September 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.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.
The ultimate outcome of this matter cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a 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 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

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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 nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the 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 Facility
Resource
Approximate Nameplate Capacity (MW)
Location
Percentage Ownership
Actual COD
PPA Counterparties
PPA Contract Period
Bethel
Wind
276
Castro County, TX
100
%
 
January 2017
Google Energy, LLC
12 years
The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The 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 September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.
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 nine months ended September 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 September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.

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Project Facility
Resource
Approximate Nameplate Capacity (MW)
Location
Actual/Expected COD
PPA Counterparties
PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East Pecos
Solar
120
Pecos County, TX
March 2017
Austin Energy
15 years
Lamesa
Solar
102
Dawson County, TX
April 2017
City of Garland, Texas
15 years
 
 
 
 
 
 
 
Projects Under Construction as of September 30, 2017
Cactus Flats(*)
Wind
148
Concho County, TX
Third quarter 2018
General Motors, LLC
and
General Mills Operations, LLC
12 years
and
15 years
Mankato
Natural Gas
345
Mankato, MN
Second quarter 2019
Northern States Power Company
20 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, one 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 U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements

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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 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 September 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 $895 million for the first nine months of 2017 compared to $269 million for the first nine 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, 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 $1.5 billion for the first nine months of 2017 primarily due to payments for renewable acquisitions and the construction of generating facilities. Net cash used for financing activities totaled $325 million for the first nine months of 2017 primarily due to common stock dividend payments, a decrease in notes payable, and distributions to noncontrolling interests, partially offset by capital 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 nine 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 $461 million decrease in 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 commitments. Approximately $864 million will be required to repay maturities of long-term debt through September 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 September 30, 2017, Southern Power's current liabilities exceeded current assets by $497 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. 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 September 30, 2017.

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Details of commercial paper 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
$
120

1.5
%
 
$
322

 
1.5
%
 
$
416

(*)
Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.
At September 30, 2017, Southern Power had a committed credit facility (Facility) of $750 million, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, Southern Power amended 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 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.
Southern Power also has a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At September 30, 2017, $111 million has been used for letters of credit 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, and transmission.

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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
$
37

At BBB- and/or Baa3
$
398

At BB+ and/or Ba1(*)
$
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 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 addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
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)
Operating Revenues:
 
 
 
 
 
 
 
 
 
 
Natural gas revenues (includes revenue
taxes of $9, $9, $75, $9, and $57 for the
periods presented, respectively)
$
532

 
$
518

 
$
2,746

 
$
518

 
 
$
1,841

Other revenues
33

 
25

 
95

 
25

 
 
64

Total operating revenues
565

 
543

 
2,841

 
543

 
 
1,905

Operating Expenses:
 
 
 
 
 
 
 
 
 
 
Cost of natural gas
134

 
133

 
1,085

 
133

 
 
755

Cost of other sales
7

 
2

 
20

 
2

 
 
14

Other operations and maintenance
205

 
216

 
671

 
216

 
 
454

Depreciation and amortization
125

 
116

 
370

 
116

 
 
206

Taxes other than income taxes
26

 
29

 
140

 
29

 
 
99

Merger-related expenses

 
35

 

 
35

 
 
56

Total operating expenses
497

 
531

 
2,286

 
531

 
 
1,584

Operating Income
68

 
12

 
555

 
12

 
 
321

Other Income and (Expense):
 
 
 
 
 
 
 
 
 
 
Earnings from equity method investments
32

 
29

 
100

 
29

 
 
2

Interest expense, net of amounts capitalized
(51
)
 
(39
)
 
(145
)
 
(39
)
 
 
(96
)
Other income (expense), net
18

 
9

 
26

 
9

 
 
5

Total other income and (expense)
(1
)
 
(1
)
 
(19
)
 
(1
)
 
 
(89
)
Earnings Before Income Taxes
67

 
11

 
536

 
11

 
 
232

Income taxes
52

 
7

 
233

 
7

 
 
87

Net Income
15

 
4

 
303

 
4

 
 
145

Less: Net income attributable to
noncontrolling interest

 

 

 

 
 
14

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.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Successor
 
 
Predecessor
 
For the Three Months Ended September 30,
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
July 1, 2016 through September 30,
 
 
January 1, 2016 through
June 30,
 
2017
 
2016
 
2017
 
2016
 
 
2016
 
(in millions)
 
 
(in millions)
Net Income
$
15

 
$
4

 
$
303

 
$
4

 
 
$
145

Other comprehensive income (loss):
 
 
 
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
 
 
 
Changes in fair value, net of tax of
$-, $(2), $(2), $(2), and $(23),
respectively

 
(3
)
 
(3
)
 
(3
)
 
 
(41
)
Reclassification adjustment for
amounts included in net income,
net of tax of $-, $-, $-, $-, and $-,
respectively

 

 

 

 
 
1

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

 

 

 

 
 
5

Total other comprehensive income (loss)

 
(3
)
 
(3
)
 
(3
)
 
 
(35
)
Comprehensive Income
15

 
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.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
Successor
 
 
Predecessor
 
For the Nine Months Ended September 30,
 
July 1, 2016 through September 30,
 
 
January 1, 2016 through
June 30,
 
2017
 
2016
 
 
2016
 
(in millions)
 
 
(in millions)
Operating Activities:
 
 
 
 
 
 
Net income
$
303

 
$
4

 
 
$
145

Adjustments to reconcile net income
to net cash provided from operating activities —
 
 
 
 
 
 
Depreciation and amortization, total
370

 
116

 
 
206

Deferred income taxes
265

 
(30
)
 
 
8

Pension, postretirement, and other employee benefits
(4
)
 
(123
)
 
 
5

Stock based compensation expense
25

 
11

 
 
20

Hedge settlements

 
(35
)
 
 
(26
)
Mark-to-market adjustments
(32
)
 
17

 
 
162

Other, net
(67
)
 
(47
)
 
 
(82
)
Changes in certain current assets and liabilities —
 
 
 
 
 
 
-Receivables
534

 
(18
)
 
 
181

-Natural gas for sale, net of temporary LIFO liquidation

 
(222
)
 
 
273

-Prepaid income taxes
(7
)
 
1

 
 
151

-Other current assets
(42
)
 
(36
)
 
 
37

-Accounts payable
(169
)
 
78

 
 
43

-Accrued taxes
(24
)
 
(11
)
 
 
41

-Accrued compensation
(11
)
 
(36
)
 
 
(21
)
-Other current liabilities
8

 
(11
)
 
 
(30
)
Net cash provided from (used for) operating activities
1,149

 
(342
)
 
 
1,113

Investing Activities:
 
 
 
 
 
 
Property additions
(1,093
)
 
(287
)
 
 
(509
)
Cost of removal, net of salvage
(45
)
 
(21
)
 
 
(32
)
Change in construction payables, net
49

 
9

 
 
(7
)
Investment in unconsolidated subsidiaries
(128
)
 
(1,421
)
 
 
(14
)
Returned investment in unconsolidated subsidiaries
22

 
2

 
 
3

Other investing activities
3

 
3

 
 

Net cash used for investing activities
(1,192
)
 
(1,715
)
 
 
(559
)
Financing Activities:
 
 
 
 
 
 
Increase (decrease) in notes payable, net
(323
)
 
472

 
 
(896
)
Proceeds —
 
 
 
 
 
 
First mortgage bonds
200

 

 
 
250

Capital contributions from parent company
79

 
1,089

 
 

Senior notes
450

 
900

 
 
350

Redemptions and repurchases —
 
 
 
 
 
 
Medium-term notes
(22
)
 

 
 

First mortgage bonds

 

 
 
(125
)
Senior notes

 
(300
)
 
 

Distributions to noncontrolling interest

 

 
 
(19
)
Payment of common stock dividends
(332
)
 
(63
)
 
 
(128
)
Other financing activities
(7
)
 
(8
)
 
 
10

Net cash provided from (used for) financing activities
45

 
2,090

 
 
(558
)
Net Change in Cash and Cash Equivalents
2

 
33

 
 
(4
)
Cash and Cash Equivalents at Beginning of Period
19

 
15

 
 
19

Cash and Cash Equivalents at End of Period
$
21

 
$
48

 
 
$
15

Supplemental Cash Flow Information:
 
 
 
 
 
 
Cash paid (received) during the period for —
 
 
 
 
 
 
Interest (net of $9, $2, and $3 capitalized, respectively)
$
146

 
$
86

 
 
$
119

Income taxes, net
17

 
54

 
 
(100
)
Noncash transactions —
Accrued property additions at end of period
112

 
50

 
 
41

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30, 2017
 
At December 31, 2016
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
21

 
$
19

Receivables —
 
 
 
 
Energy marketing receivables
 
427

 
623

Customer accounts receivable
 
221

 
364

Unbilled revenues
 
61

 
239

Other accounts and notes receivable
 
61

 
76

Accumulated provision for uncollectible accounts
 
(26
)
 
(27
)
Materials and supplies
 
24

 
26

Natural gas for sale
 
631

 
631

Prepaid expenses
 
103

 
80

Assets from risk management activities, net of collateral
 
103

 
128

Other regulatory assets, current
 
96

 
81

Other current assets
 
25

 
10

Total current assets
 
1,747

 
2,250

Property, Plant, and Equipment:
 
 
 
 
In service
 
15,383

 
14,508

Less: Accumulated depreciation
 
4,567

 
4,439

Plant in service, net of depreciation
 
10,816

 
10,069

Construction work in progress
 
596

 
496

Total property, plant, and equipment
 
11,412

 
10,565

Other Property and Investments:
 
 
 
 
Goodwill
 
5,967

 
5,967

Equity investments in unconsolidated subsidiaries
 
1,609

 
1,541

Other intangible assets, net of amortization of $100 and $34
at September 30, 2017 and December 31, 2016, respectively
 
300

 
366

Miscellaneous property and investments
 
21

 
21

Total other property and investments
 
7,897

 
7,895

Deferred Charges and Other Assets:
 
 
 
 
Other regulatory assets, deferred
 
944

 
973

Other deferred charges and assets
 
190

 
170

Total deferred charges and other assets
 
1,134

 
1,143

Total Assets
 
$
22,190

 
$
21,853

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


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CONDENSED CONSOLIDATED 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
 
$

 
$
22

Notes payable
 
934

 
1,257

Energy marketing trade payables
 
451

 
597

Accounts payable
 
368

 
348

Customer deposits
 
137

 
153

Accrued taxes —
 
 
 
 
Accrued income taxes
 

 
26

Other accrued taxes
 
70

 
68

Accrued interest
 
66

 
48

Accrued compensation
 
46

 
58

Liabilities from risk management activities, net of collateral
 
28

 
62

Other regulatory liabilities, current
 
126

 
102

Accrued environmental remediation, current
 
54

 
69

Other current liabilities
 
112

 
108

Total current liabilities
 
2,392

 
2,918

Long-term Debt
 
5,862

 
5,259

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
2,214

 
1,975

Employee benefit obligations
 
431

 
441

Other cost of removal obligations
 
1,656

 
1,616

Accrued environmental remediation, deferred
 
345

 
357

Other regulatory liabilities, deferred
 
35

 
51

Other deferred credits and liabilities
 
88

 
127

Total deferred credits and other liabilities
 
4,769

 
4,567

Total Liabilities
 
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
 
9,185

 
9,095

Accumulated deficit
 
(41
)
 
(12
)
Accumulated other comprehensive income
 
23

 
26

Total common stockholder's equity
 
9,167

 
9,109

Total Liabilities and Stockholder's Equity
 
$
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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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 Disposition 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 $28 million and $86 million from this investment in the successor third quarter and year-to-date 2017, respectively, and $27 million in September 2016. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.
In October 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar. See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
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 most of the earnings 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
Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher, as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
RESULTS OF OPERATIONS
Net Income
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)
 
(% change)
$11
 
N/M
N/M - Not meaningful
Net income attributable to Southern Company Gas was $15 million for the third quarter 2017 compared to $4 million for the corresponding period in 2016. This increase was primarily due to $11 million of additional income from infrastructure replacement programs and base rate increases, net of associated depreciation, and a $7 million gain from the settlement of contractor litigation claims, partially offset by $12 million lower net income at wholesale gas services. Also contributing to the increase was $24 million in Merger-related expenses in the third quarter 2016, partially offset by $23 million of additional deferred income tax expense in the 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 included in net income for these periods were $24 million and $41 million, respectively, of Merger-related expenses and $14 million of net income attributable to noncontrolling interest in the predecessor period of January 1, 2016 through June 30, 2016. As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in 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 2016.
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 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.
 
 
Successor
 
 
Predecessor
 
 
Year-to-Date 2017
 
July 1, 2016 through September 30, 2016
 
 
January 1, 2016 through June 30, 2016
 
 
(in millions)
 
(in millions)
 
 
(in millions)
Natural gas revenues
 
$
2,746

 
$
518

 
 
$
1,841

For the successor year-to-date 2017, natural gas revenues included recovery of $1.1 billion in cost of natural gas and $95 million in net revenues from wholesale gas services, net of $14 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues were $69 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, partially offset by a $16 million decrease attributable to warmer-than-normal weather, net of hedging.
For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, natural gas revenues included recovery of $133 million and $755 million, respectively, in cost of natural gas, as well as $8 million and $32 million, respectively, in net losses from wholesale gas services. Also included in natural gas revenues for the predecessor period of January 1, 2016 through June 30, 2016 was a $7 million decrease attributable to warmer-than-normal weather, net of hedging.
See "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 of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
During Heating Season natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact 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.
 
 
Year-to-Date
 
2017
vs.
2016
 
2017
vs.
normal
 
 
Normal(a)
 
2017
 
2016
 
(warmer)
 
(warmer)
Illinois(b)
 
3,817

 
3,146

 
3,353

 
(6.2
)%
 
(17.6
)%
Georgia
 
1,631

 
1,008

 
1,449

 
(30.4
)%
 
(38.2
)%
(a)
Normal represents the 10-year average from January 1, 2007 through September 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 3,580 for the first nine months from 1998 through 2007.
For the third quarters 2017 and 2016, the weather-related pre-tax income impact was immaterial.
Southern Company Gas hedged its exposure to warmer-than-normal weather at Nicor Gas in Illinois; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $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 Georgia and Illinois;

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therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for year-to-date 2017 and there was no impact for year-to-date 2016.
The following table provides the number of customers served by Southern Company Gas at September 30, 2017 and 2016:
 
September 30,
 
 
 
2017
 
2016
 
2017 vs. 2016
 
(in thousands, except market share %)
 
(% change)
Gas distribution operations
4,555

 
4,522

 
0.7
 %
Gas marketing services
 
 
 
 
 
Energy customers(*)
756

 
626

 
20.8
 %
Market share of energy customers in Georgia
28.8
%
 
29.4
%
 
 
Service contracts
1,183

 
1,189

 
(0.5
)%
(*)
Includes approximately 140,000 customers as of September 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 as it expects continued improvement in the new housing market and low natural gas prices.
Gas marketing services' market share in Georgia decreased at September 30, 2017 compared to 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
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)
 
(% change)
$1
 
0.8
In the third quarter 2017, cost of natural gas was $134 million compared to $133 million for the corresponding period in 2016. This increase reflected 7% higher natural gas prices during the third quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas.
 
 
Successor
 
 
Predecessor
 
 
Year-to-Date 2017
 
July 1, 2016 through September 30, 2016
 
 
January 1, 2016 through June 30, 2016
 
 
(in millions)
 
(in millions)
 
 
(in millions)
Cost of natural gas
 
$
1,085

 
$
133

 
 
$
755

Cost of natural gas primarily reflected an increase of 38% in natural gas prices during the year-to-date 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.
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 Gas Revenues" herein.

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The following table details the volumes of natural gas sold during all periods presented.
 
Third Quarter
 
2017
vs.
2016
 
Year-to-Date
 
2017
vs.
2016
 
2017
 
2016
 
% Change
 
2017
 
2016
 
% Change
Gas distribution operations 
(mmBtu in millions)
 
 
 
 
 
 
 
 
 
 
 
Firm
73

 
71

 
2.8
 %
 
438

 
467

 
(6.2
)%
Interruptible
22

 
22

 
 %
 
71

 
71

 
 %
Total
95

 
93

 
2.2
 %
 
509

 
538

 
(5.4
)%
Gas marketing services 
(mmBtu in millions)
 
 
 
 
 
 
 
 
 
 
 
Firm:
 
 
 
 
 
 
 
 
 
 
 
Georgia
3

 
3

 
 %
 
11

 
25

 
(56.0
)%
Illinois
1

 
1

 
 %
 
4

 
8

 
(50.0
)%
Other emerging markets
2

 
2

 
 %
 
7

 
9

 
(22.2
)%
Interruptible:
 
 
 
 
 
 
 
 
 
 
 
Large commercial and industrial
3

 
3

 
 %
 
8

 
10

 
(20.0
)%
Total
9

 
9

 
 %
 
30

 
52

 
(42.3
)%
Wholesale gas services
(mmBtu in millions/day)
 
 
 
 
 
 
 
 
 
 
 
Daily physical sales
6.3

 
7.6

 
(17.1
)%
 
6.4

 
7.6

 
(15.8
)%
Other Operations and Maintenance Expenses
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 $205 million compared to $216 million for the corresponding 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 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 for the successor year-to-date 2017 reflected increased compensation expenses due to timing, partially offset by low bad debt expense. For all periods presented, other operations and maintenance expenses primarily includes professional services, including pipeline compliance and maintenance and legal services, as well as compensation and benefit costs.

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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 $26 million compared to $29 million for the corresponding period in 2016. The decrease primarily 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 during the successor periods.

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Earnings from Equity Method Investments
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)
 
(% change)
$3
 
10.3
In the third quarter 2017, earnings from equity method investments were $32 million compared to $29 million for 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 $86 million in earnings from SNG and $14 million in earnings from all other investments.
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
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)
 
(% change)
$12
 
30.8
In the third quarter 2017, interest expense, net of amounts capitalized was $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 year-to-date 2017 and 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 and $9 million, respectively, resulting from the fair value adjustment of long-term debt in acquisition accounting.
Income Taxes
Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)
 
(% change)
$45
 
N/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 deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017 and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, 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 income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation and the allocation of new tax apportionment factors, as well as increased income taxes from higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.
Performance and Non-GAAP Measures
Prior to the Merger, Southern Company Gas evaluated segment performance using earnings before interest and taxes (EBIT), which includes operating income, earnings from equity method investments, and other income

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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 third quarters 2017 and 2016 and the successor year-to-date 2017 presented herein is considered a non-GAAP measure. Southern Company Gas also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes that the presentation of segment EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues 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
 
 
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)
Operating Income
 
$
68

 
$
12

 
$
555

 
$
12

 
 
$
321

Other operating expenses(a)
 
356

 
396

 
1,181

 
396

 
 
815

Revenue taxes(b)
 
(8
)
 
(8
)
 
(74
)
 
(8
)
 
 
(56
)
Adjusted Operating Margin
 
$
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
 
 
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.
Segment Information
Adjusted operating margin, operating expenses, and Southern Company Gas' primary performance metric for each segment is illustrated in the tables below. See Note (K) to the Condensed Financial Statements herein for additional information.

Successor
 
Third Quarter 2017

Third Quarter 2016

 Adjusted Operating

Operating

Net Income

Adjusted Operating

Operating

Net Income

Margin(*)

Expenses(*)

(Loss)

Margin(*)

Expenses(*)

(Loss)

(in millions)

(in millions)
Gas distribution operations
$
379


$
271


$
52


$
353


$
284


$
27

Gas marketing services
51


48


1


45


51


(4
)
Wholesale gas services
(25
)

11


(23
)

(8
)

10


(11
)
Gas midstream operations
12


13


14


9


13


14

All other
2


8


(29
)

2


31


(22
)
Intercompany eliminations
(3
)

(3
)



(1
)

(1
)


Consolidated
$
416


$
348


$
15


$
400


$
388


$
4

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

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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 other
7

 
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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$119 million in interest expense, net of amounts capitalized and $144 million in income tax expense. Adjusted operating margin reflects $69 million in additional revenue from continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth, partially offset by a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $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 Period of January 1, 2016 through June 30, 2016
EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expenses, and $2 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, 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 Third 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 $36 million includes $213 million in adjusted operating margin and $149 million in operating expenses, which resulted in EBIT of $64 million. Net income also includes $4 million in interest expense and $24 million in income tax expense. Adjusted operating margin reflects a $10 million negative impact of warmer-than-normal weather, net of hedging, and $7 million in unrealized hedge losses, net of recoveries. Operating expenses include $30 million in additional amortization of intangible assets established in the application of acquisition accounting.
Successor Period of July 1, 2016 through September 30, 2016
Net loss of $4 million includes $45 million in adjusted operating margin and $51 million in operating expenses, which resulted in a loss before interest and taxes of $6 million. Also included in net loss is $2 million in income tax benefit.

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Predecessor Period of January 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 Third 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 income of $28 million includes $93 million in adjusted operating margin and $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 $17 million. Also included in net loss is $1 million in interest expense and $7 million in income tax benefit.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.

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The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.
 
Successor
 
 
Predecessor
 
Third Quarter 2017
 
Third Quarter 2016
 
Year-to-Date 2017
 
July 1, 2016 through September 30, 2016
 
 
January 1, 2016
through
June 30,
2016
 
(in millions)
 
 
(in millions)
Commercial activity recognized
$
3

 
$
10

 
$
80

 
10

 
 
$
34

Gain (loss) on storage derivatives
4

 
11

 
13

 
11

 
 
(38
)
Gain (loss) on transportation and forward
commodity derivatives
(22
)
 
(7
)
 
14

 
(7
)
 
 
(31
)
LOCOM adjustments, net of current period
recoveries

 

 

 

 
 
(1
)
Purchase accounting adjustments
(10
)
 
(22
)
 
(14
)
 
(22
)
 
 

Adjusted Operating Margin
$
(25
)
 
$
(8
)
 
$
93

 
$
(8
)
 
 
$
(36
)
Change in Commercial Activity
The 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 nine 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 September 30, 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
 
 
 
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)
2017
22.0

 
$
4

 
$
(13
)
2018 and thereafter
40.0

 
17

 
28

Total at September 30, 2017
62.0

 
$
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 include SNG, 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 Third 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 $38 million includes $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, consisting primarily of earnings from equity method

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investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of $25 million. Also included in net income is $11 million in income tax expense.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $6 million includes $15 million in adjusted operating margin, $24 million in operating expenses, and $3 million of other income (expense), net.
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 inclusion of Southern Company Gas into the 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 third 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.

Successor

Third Quarter 2017

Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services
Gas Midstream Operations
All Other
Intercompany Elimination
Consolidated

(in millions)
Consolidated Net Income
(Loss)
$
52

$
1

$
(23
)
$
14

$
(29
)
$

$
15

Income taxes (benefit)
34

1

(15
)
9

23


52

Interest expense, net of
amounts capitalized
39

1

2

9



51

EBIT
$
125

$
3

$
(36
)
$
32

$
(6
)
$

$
118

 
 
Successor
 
 
Third Quarter 2016
 
 
Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services
Gas Midstream Operations
All Other
Intercompany Elimination
Consolidated
 
 
(in millions)
Consolidated Net Income
(Loss)
 
$
27

$
(4
)
$
(11
)
$
14

$
(22
)
$

$
4

Income taxes (benefit)
 
16

(2
)
(7
)
11

(11
)

7

Interest expense, net of
amounts capitalized
 
32


1


6


39

EBIT
 
$
75

$
(6
)
$
(17
)
$
25

$
(27
)
$

$
50

 
Successor
 
Year-to-Date 2017
 
Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services
Gas Midstream Operations
All Other
Intercompany Elimination
Consolidated
 
(in millions)
Consolidated Net Income
(Loss)
$
223

$
36

$
28

$
38

$
(22
)
$

$
303

Income taxes
144

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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Successor

Third Quarter 2017

Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services
Gas Midstream Operations
All Other
Intercompany Elimination
Consolidated

(in millions)
Operating Income (Loss)
$
108

$
3

$
(36
)
$
(1
)
$
(6
)
$

$
68

Other operating expenses(a)
279

48

11

13

8

(3
)
356

Revenue tax expense(b)
(8
)





(8
)
Adjusted Operating
Margin
$
379

$
51

$
(25
)
$
12

$
2

$
(3
)
$
416

 
Successor
 
Third Quarter 2016
 
Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services
Gas Midstream Operations
All Other
Intercompany Elimination
Consolidated
 
(in millions)
Operating Income (Loss)
$
69

$
(6
)
$
(18
)
$
(4
)
$
(29
)
$

$
12

Other operating expenses(a)
292

51

10

13

31

(1
)
396

Revenue tax expense(b)
(8
)





(8
)
Adjusted Operating
Margin
$
353

$
45

$
(8
)
$
9

$
2

$
(1
)
$
400

 
Successor
 
Year-to-Date 2017
 
Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services
Gas Midstream Operations
All Other
Intercompany Elimination
Consolidated
 
(in millions)
Operating Income (Loss)
$
463

$
64

$
53

$
(10
)
$
(15
)
$

$
555

Other operating expenses(a)
940

149

40

38

22

(8
)
1,181

Revenue tax expense(b)
(74
)





(74
)
Adjusted Operating
Margin
$
1,329

$
213

$
93

$
28

$
7

$
(8
)
$
1,662

 
Predecessor
 
January 1, 2016 through June 30, 2016
 
Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services
Gas Midstream Operations
All Other
Intercompany Elimination
Consolidated
 
(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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS


FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of 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 by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
On July 6, 2017, the State of Illinois enacted tax legislation that repealed its non-combination tax rule and increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation required Southern Company Gas to increase accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect these changes, $15 million of which was expensed and $9 million was recorded as a regulatory asset. In addition, during the third quarter 2017, Southern Company calculated new apportionment factors in several states to include Southern Company Gas in its consolidated tax filings, which resulted in $8 million of additional deferred income tax expenses.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. The execution of the asset purchase agreements triggered an interim assessment of goodwill, which is currently being performed with the assistance of a third-party valuation specialist. The preliminary results of this valuation indicate that the estimated fair values of the reporting units with goodwill exceed their carrying amounts and are not at risk of impairment. See OVERVIEW "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sales.
Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of its gas marketing services and wholesale gas services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability. Over the longer-term, 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.
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.
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (LDNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "FERC Matters" of Southern Company Gas in Item 7 and Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information regarding the Dalton Pipeline project.
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 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, 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 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 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

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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 Gas
98

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


Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The following table 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.

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


INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
Note
 
Page Number
A
B
C
D
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.
Registrant
Applicable Notes
Southern Company
A, B, C, D, E, F, G, H, I, J, K
Alabama Power
A, B, C, E, F, G, H
Georgia Power
A, B, C, E, F, G, H
Gulf Power
A, B, C, E, F, G, H
Mississippi Power
A, B, C, E, F, G, H
Southern Power
A, B, C, D, E, G, H, I
Southern Company Gas
A, B, C, E, F, G, H, I, J, K


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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)

(A)
INTRODUCTION
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 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.

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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

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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.

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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, 2017
At 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 services
1,265

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.

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

Other intangible assets were as follows:
 
At September 30, 2017
 
At December 31, 2016
 
Gross Carrying Amount
Accumulated Amortization
Other
Intangible Assets, Net
 
Gross Carrying Amount
Accumulated Amortization
Other
Intangible Assets, Net
 
(in millions)
 
(in millions)
Southern Company
 
 
 
 
 
 
 
Other intangible assets subject to amortization:
 
 
 
 
 
 
 
Customer relationships
$
288

$
(70
)
$
218

 
$
268

$
(32
)
$
236

Trade names
159

(15
)
144

 
158

(5
)
153

Storage and transportation contracts
64

(27
)
37

 
64

(2
)
62

PPA fair value adjustments
456

(41
)
415

 
456

(22
)
434

Other
16

(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 names
115

(8
)
107

 
115

(2
)
113

Wholesale gas services
 
 
 
 
 
 
 
Storage and transportation contracts
64

(27
)
37

 
64

(2
)
62

Total other intangible assets subject to amortization
$
400

$
(100
)
$
300

 
$
400

$
(34
)
$
366


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

Amortization associated with other intangible assets was as follows:
 
Three Months Ended
Nine 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 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 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 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 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.

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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

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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

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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 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

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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.

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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 Clause
Balance Sheet Line Item
September 30,
2017
December 31,
2016


(in millions)
Rate CNP Compliance
Deferred over recovered regulatory clause revenues
$
9

$

Rate CNP Compliance(*)
Deferred under recovered regulatory clause revenues

9

Rate CNP PPA
Deferred under recovered regulatory clause revenues
17

142

Retail Energy Cost Recovery(*)
Other regulatory liabilities, current

76

Natural Disaster Reserve
Other regulatory liabilities, deferred
51

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.

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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.

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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

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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

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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

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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, 2017
4.6

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.

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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 tax
1.5

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.

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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.

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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 Clause
Balance Sheet Line Item
September 30,
2017
December 31,
2016


(in millions)
Fuel Cost Recovery
Under recovered regulatory clause revenues
$
13

$

Fuel Cost Recovery
Other regulatory liabilities, current

15

Purchased Power Capacity Recovery
Under recovered regulatory clause revenues
1


Environmental Cost Recovery
Other regulatory liabilities, current
1


Environmental Cost Recovery
Under recovered regulatory clause revenues

13

Energy Conservation Cost Recovery
Under recovered regulatory clause revenues
1

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

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(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

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(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 Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase 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 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. 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.

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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 $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.
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

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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 initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue 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.
Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional 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.
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

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(UNAUDITED)

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.
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 the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.
Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.
While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs

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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.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast

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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 December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.
In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.
As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate

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order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).
On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.
Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.
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 Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.

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

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Bonus Depreciation
All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (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, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. See Note (G) for additional information.

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(C)
FAIR VALUE MEASUREMENTS
As of September 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:
 
 
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)
Southern Company
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Energy-related derivatives(a)(b)
$
231

 
$
184

 
$

 
$

 
$
415

Interest rate derivatives

 
5

 

 

 
5

Foreign currency derivatives

 
103

 

 

 
103

Nuclear decommissioning trusts(c)
752

 
1,004

 

 
26

 
1,782

Cash equivalents
1,271

 

 

 

 
1,271

Other investments
9

 

 
1

 

 
10

Total
$
2,263

 
$
1,296

 
$
1

 
$
26

 
$
3,586

Liabilities:
 
 
 
 
 
 
 
 
 
Energy-related derivatives(a)(b)
$
265

 
$
146

 
$

 
$

 
$
411

Interest rate derivatives

 
24

 

 

 
24

Foreign currency derivatives

 
23

 

 

 
23

Contingent consideration

 

 
20

 

 
20

Total
$
265

 
$
193

 
$
20

 
$

 
$
478

 
 
 
 
 
 
 
 
 
 
Alabama Power
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Energy-related derivatives
$

 
$
9

 
$

 
$

 
$
9

Nuclear decommissioning trusts:(d)
 
 
 
 
 
 
 
 


Domestic equity
422

 
81

 

 

 
503

Foreign equity
60

 
57

 

 

 
117

U.S. Treasury and government agency securities

 
27

 

 

 
27

Corporate bonds
19

 
150

 

 

 
169

Mortgage and asset backed securities

 
18

 

 

 
18

Private Equity

 

 

 
26

 
26

Other

 
8

 

 

 
8

Cash equivalents
808

 

 

 

 
808

Total
$
1,309

 
$
350

 
$

 
$
26

 
$
1,685

Liabilities:
 
 
 
 
 
 
 
 
 
Energy-related derivatives
$

 
$
7

 
$

 
$

 
$
7


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

 
$
18

 
$

 
$

 
$
18

Interest rate derivatives

 
1

 

 

 
1

Nuclear decommissioning trusts:(d) (e)
 
 
 
 
 
 
 
 
 
Domestic equity
235

 
1

 

 

 
236

Foreign equity

 
156

 

 

 
156

U.S. Treasury and government agency securities

 
225

 

 

 
225

Municipal bonds

 
64

 

 

 
64

Corporate bonds

 
160

 

 

 
160

Mortgage and asset backed securities

 
38

 

 

 
38

Other
16

 
19

 

 

 
35

Cash equivalents
112

 

 

 

 
112

Total
$
363

 
$
682

 
$

 
$

 
$
1,045

Liabilities:
 
 
 
 
 
 
 
 
 
Energy-related derivatives
$

 
$
11

 
$

 
$

 
$
11

Interest rate derivatives

 
3

 

 

 
3

Total
$

 
$
14

 
$

 
$

 
$
14

 
 
 
 
 
 
 
 
 
 
Gulf Power
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Cash equivalents
$
21

 
$

 
$

 
$

 
$
21

Liabilities:
 
 
 
 
 
 
 
 
 
Energy-related derivatives
$

 
$
22

 
$

 
$

 
$
22

 
 
 
 
 
 
 
 
 
 
Mississippi Power
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Energy-related derivatives
$

 
$
3

 
$

 
$

 
$
3

Interest rate derivatives

 
2

 

 

 
2

Cash equivalents
209

 

 

 

 
209

Total
$
209

 
$
5

 
$

 
$

 
$
214

Liabilities:
 
 
 
 
 
 
 
 
 
Energy-related derivatives
$

 
$
7

 
$

 
$

 
$
7

 
 
 
 
 
 
 
 
 
 

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

 
$
9

 
$

 
$

 
$
9

Foreign currency derivatives

 
103

 

 

 
103

Cash equivalents
90

 

 

 

 
90

Total
$
90

 
$
112

 
$

 
$

 
$
202

Liabilities:
 
 
 
 
 
 
 
 
 
Energy-related derivatives
$

 
$
4

 
$

 
$

 
$
4

Foreign currency derivatives

 
23

 

 

 
23

Contingent consideration

 

 
20

 

 
20

Total
$


$
27


$
20


$


$
47

 
 
 
 
 
 
 
 
 
 
Southern Company Gas
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Energy-related derivatives(a)(b)
$
231

 
$
145

 
$

 
$

 
$
376

Liabilities:
 
 
 
 
 
 
 
 
 
Energy-related derivatives(a)(b)
$
265

 
$
95

 
$

 
$

 
$
360

(a)
Excludes $13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)
Excludes cash collateral of $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 September 30, 2017, approximately $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 $50 million and $168 million, respectively, for the three and nine months ended September 30, 2017, and by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016. Alabama Power recorded increases in fair value of $25 million and $87 million, respectively, for the three and nine months ended September 30, 2017 and $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 as a change in regulatory liabilities related to its AROs. Georgia Power recorded increases in fair value of $25 million and $81 million, respectively, for the three and nine months ended September 30, 2017 and $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 as a change in its regulatory asset related to its AROs.
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

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observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) 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 September 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 September 30, 2017:
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
 
(in millions)
 
 
 
 
Southern Company
$
26

 
$
24

 
Not Applicable
 
Not Applicable
Alabama Power
$
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.

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(UNAUDITED)

As of September 30, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
Carrying
Amount
 
Fair
Value
 
(in millions)
Long-term debt, including securities due within one year:
 
 
 
Southern Company
$
47,269

 
$
49,348

Alabama Power
$
7,404

 
$
8,031

Georgia Power
$
11,713

 
$
12,237

Gulf Power
$
1,292

 
$
1,352

Mississippi Power
$
2,123

 
$
2,117

Southern Power
$
5,810

 
$
5,916

Southern Company Gas
$
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 September 30, 2017
Three Months Ended September 30, 2016
Nine Months Ended September 30, 2017
Nine Months Ended September 30, 2016
 
(in millions)
As reported shares
1,003

968

998

940

Effect of options and performance share award units
7

7

7

5

Diluted shares
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 nine months ended September 30, 2017 and 2016.

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Changes in Stockholders' Equity
The following table presents year-to-date changes in stockholders' equity of Southern Company:
 
Number of
Common Shares
 
Common
Stockholders'
Equity
Preferred and
Preference
Stock of
Subsidiaries
 
Total
Stockholders'
Equity
 
Issued
Treasury
 
Noncontrolling Interests(*)
 
(in thousands)
 
(in millions)
Balance at December 31, 2016
991,213

(819
)
 
$
24,758

$
609

$
1,245

$
26,612

Consolidated net income attributable to Southern Company


 
347



347

Other comprehensive income (loss)


 
(2
)


(2
)
Stock issued
13,308


 
613



613

Stock-based compensation


 
97



97

Cash dividends on common stock


 
(1,716
)


(1,716
)
Preference stock redemption


 

(150
)

(150
)
Contributions from noncontrolling interests


 


77

77

Distributions to noncontrolling interests


 


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


 


45

45

Reclassification from redeemable noncontrolling interests


 


114

114

Other

(75
)
 
(15
)
3

1

(11
)
Balance at September 30, 2017
1,004,521

(894
)
 
$
24,082

$
462

$
1,395

$
25,939

 
 
 
 
 
 
 
 
Balance at December 31, 2015
915,073

(3,352
)
 
$
20,592

$
609

$
781

$
21,982

Consolidated net income attributable to Southern Company


 
2,251



2,251

Other comprehensive income (loss)


 
(95
)


(95
)
Stock issued
65,725

2,599

 
3,265



3,265

Stock-based compensation


 
94



94

Cash dividends on common stock


 
(1,553
)


(1,553
)
Contributions from noncontrolling interests


 


357

357

Distributions to noncontrolling interests


 


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


 


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


 


36

36

Other

(46
)
 
(7
)


(7
)
Balance at September 30, 2016
980,798

(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.

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(UNAUDITED)

(E)
FINANCING
Going Concern
As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to approximately $935 million that will be required through September 30, 2018 to fund maturities of long-term debt and $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 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).
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-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 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.

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(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 September 30, 2017 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 million (comprised of approximately $509 million at Georgia Power, $140 million at Gulf Power, and $50 million at Mississippi Power) of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.

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(UNAUDITED)

The following table outlines the committed credit arrangements by company as of September 30, 2017:
 
Expires
 
 
 
Executable Term
Loans
 
Expires Within
One Year
Company
2017
2018
2019
2020
2022
 
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 Power
30

195

25

30


 
280

 
280

 
45

 

 

 
40

Mississippi Power
100





 
100

 
100

 

 

 

 
100

Southern Power Company(b)




750

 
750

 
728

 

 

 

 

Southern Company Gas(c)




1,900

 
1,900

 
1,861

 

 

 

 

Other

30




 
30

 
30

 
20

 

 
20

 
10

Southern Company Consolidated
$
130

$
260

$
25

$
530

$
7,200

 
$
8,145

 
$
8,066

 
$
65

 
$

 
$
20

 
$
185

(a)
Represents the Southern Company parent entity.
(b)
Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.
(c)
Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

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(UNAUDITED)

Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first 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 Power
550

 
200

 
36

 

 

Georgia Power
1,350

 
450

 
65

 
370

 
13

Gulf Power
300

 
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.
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 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.
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

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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.
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 remarketed these bonds to the 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, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.
Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
Also in August 2017, Georgia Power purchased and held $38 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,

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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

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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.

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

Components of the net periodic benefit costs for the three and nine months ended September 30, 2017 and 2016 are presented in the following tables.
Pension Plans
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
(in millions)
Three Months Ended September 30, 2017
 
 
 
 
 
 
 
 
 
Service cost
$
73

 
$
15

 
$
19

 
$
3

 
$
4

Interest cost
114

 
25

 
34

 
5

 
5

Expected return on plan assets
(224
)
 
(49
)
 
(71
)
 
(10
)
 
(9
)
Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
3

 
1

 

 

 

Net (gain)/loss
41

 
10

 
15

 
2

 
1

Net periodic pension cost (income)
$
7

 
$
2

 
$
(3
)
 
$

 
$
1

Nine Months Ended September 30, 2017
 
 
 
 
 
 
 
 
 
Service cost
$
220

 
$
47

 
$
56

 
$
10

 
$
11

Interest cost
341

 
73

 
103

 
15

 
15

Expected return on plan assets
(673
)
 
(147
)
 
(212
)
 
(29
)
 
(29
)
Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
9

 
2

 
2

 

 
1

Net (gain)/loss
122

 
31

 
43

 
5

 
5

Net periodic pension cost (income)
$
19

 
$
6

 
$
(8
)
 
$
1

 
$
3

Three Months Ended September 30, 2016
 
 
 
 
 
 
 
 
 
Service cost
$
68

 
$
14

 
$
17

 
$
3

 
$
3

Interest cost
110

 
23

 
34

 
5

 
4

Expected return on plan assets
(203
)
 
(46
)
 
(64
)
 
(9
)
 
(9
)
Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
3

 
1

 
1

 

 
1

Net (gain)/loss
45

 
10

 
14

 
2

 
2

Net periodic pension cost
$
23

 
$
2

 
$
2

 
$
1

 
$
1

Nine Months Ended September 30, 2016
 
 
 
 
 
 
 
 
 
Service cost
$
192

 
$
43

 
$
52

 
$
9

 
$
9

Interest cost
311

 
71

 
102

 
14

 
14

Expected return on plan assets
(577
)
 
(138
)
 
(193
)
 
(26
)
 
(26
)
Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
10

 
2

 
4

 
1

 
1

Net (gain)/loss
120

 
30

 
41

 
5

 
5

Net periodic pension cost
$
56

 
$
8

 
$
6

 
$
3

 
$
3


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

Pension Plans
Southern
Company
Gas
 
(in millions)
Successor – Three Months Ended September 30, 2017
 
Service cost
$
6

Interest cost
10

Expected return on plan assets
(18
)
Amortization of net (gain)/loss
5

Net periodic pension cost
$
3

Successor – Nine Months Ended September 30, 2017
 
Service cost
$
17

Interest cost
30

Expected return on plan assets
(53
)
Amortization:
 
Prior service costs
(1
)
Net (gain)/loss
15

Net periodic pension cost
$
8

Successor – July 1, 2016 through September 30, 2016
 
Service cost
$
7

Interest cost
10

Expected return on plan assets
(17
)
Amortization of regulatory asset
6

Net periodic pension cost
$
6

 
 
 
 
Predecessor – January 1, 2016 through June 30, 2016
 
Service cost
$
13

Interest cost
21

Expected return on plan assets
(33
)
Amortization:
 
Prior service costs
(1
)
Net (gain)/loss
13

Net periodic pension cost
$
13


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

Postretirement Benefits
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
(in millions)
Three Months Ended September 30, 2017
 
 
 
 
 
 
 
 
 
Service cost
$
6

 
$
1

 
$
2

 
$

 
$

Interest cost
19

 
4

 
6

 
1

 
1

Expected return on plan assets
(16
)
 
(5
)
 
(6
)
 

 

Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
2

 
1

 

 

 

Net (gain)/loss
3

 

 
3

 

 

Net periodic postretirement benefit cost
$
14

 
$
1

 
$
5

 
$
1

 
$
1

Nine Months Ended September 30, 2017
 
 
 
 
 
 
 
 
 
Service cost
$
18

 
$
4

 
$
5

 
$
1

 
$
1

Interest cost
59

 
13

 
21

 
2

 
3

Expected return on plan assets
(49
)
 
(19
)
 
(18
)
 
(1
)
 
(1
)
Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
5

 
3

 
1

 

 

Net (gain)/loss
10

 
1

 
6

 

 

Net periodic postretirement benefit cost
$
43

 
$
2

 
$
15

 
$
2

 
$
3

Three Months Ended September 30, 2016
 
 
 
 
 
 
 
 
 
Service cost
$
6

 
$
1

 
$
2

 
$

 
$

Interest cost
20

 
5

 
7

 
1

 

Expected return on plan assets
(16
)
 
(6
)
 
(6
)
 

 

Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
1

 
1

 

 

 

Net (gain)/loss
5

 

 
3

 

 
1

Net periodic postretirement benefit cost
$
16

 
$
1

 
$
6

 
$
1

 
$
1

Nine Months Ended September 30, 2016
 
 
 
 
 
 
 
 
 
Service cost
$
17

 
$
4

 
$
5

 
$
1

 
$
1

Interest cost
55

 
14

 
22

 
2

 
2

Expected return on plan assets
(44
)
 
(19
)
 
(17
)
 
(1
)
 
(1
)
Amortization:
 
 
 
 
 
 
 
 
 
Prior service costs
4

 
3

 
1

 

 

Net (gain)/loss
12

 
1

 
7

 

 
1

Net periodic postretirement benefit cost
$
44

 
$
3

 
$
18

 
$
2

 
$
3


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

Postretirement Benefits
Southern
Company
Gas
 
(in millions)
Successor – Three Months Ended September 30, 2017
 
Service cost
$
1

Interest cost
3

Expected return on plan assets
(2
)
Amortization:
 
Prior service costs
(1
)
Net (gain)/loss
1

Net periodic postretirement benefit cost
$
2

Successor – Nine Months Ended September 30, 2017
 
Service cost
$
2

Interest cost
8

Expected return on plan assets
(5
)
Amortization:
 
Prior service costs
(2
)
Net (gain)/loss
3

Net periodic postretirement benefit cost
$
6

Successor – July 1, 2016 through September 30, 2016
 
Service cost
$
1

Interest cost
2

Expected return on plan assets
(2
)
Amortization of regulatory asset
1

Net periodic postretirement benefit cost
$
2

 
 
 
 
Predecessor – January 1, 2016 through June 30, 2016
 
Service cost
$
1

Interest cost
5

Expected return on plan assets
(3
)
Amortization:
 
Prior service costs
(1
)
Net (gain)/loss
2

Net periodic postretirement benefit cost
$
4


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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 September 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 September 30, 2017, valuation allowances were as follows:
 
Mississippi Power
 
Southern Company
Gas
 
Southern Company
 
(in millions)
Federal
$

 
$
18

 
$
18

State (net of federal benefit)
46

 
1

 
64

Balance at September 30, 2017
$
46

 
$
19

 
$
82

Southern Company had valuation allowances, net of the federal benefit, of $82 million at September 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 rate was 42.6% for the nine months ended September 30, 2017 compared to 28.3% for the corresponding period in 2016. The effective tax rate increase 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.
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.


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

Mississippi Power
Mississippi Power's effective tax (benefit) rate was (30.3)% for the nine months ended September 30, 2017 compared to (282.8)% for the corresponding period in 2016. The effective tax rate increase was 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.
Southern Power
Southern Power's effective tax (benefit) rate was (66.5)% for the nine months ended September 30, 2017 compared to (88.9)% for the corresponding period in 2016. The effective tax rate increase was primarily due to a decrease in tax benefits from solar ITCs, partially offset by additional wind PTCs and state apportionment rate changes.
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 nine months ended September 30, 2017 for unrecognized tax benefits were as follows:
 
Mississippi Power
 
Southern Power
 
Southern Company
 
(in millions)
Unrecognized tax benefits as of December 31, 2016
$
465

 
$
17

 
$
484

Tax positions from current periods
2

 

 
9

Tax positions from prior periods
(175
)
 
(17
)
 
(186
)
Reductions due to settlements
(290
)
 

 
(290
)
Balance as of September 30, 2017
$
2

 
$

 
$
17


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

The tax positions from current and prior periods primarily relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC, as well as federal income tax benefits from deferred ITCs. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
The impact on the effective tax rate, if recognized, is as follows:
 
As of September 30, 2017
 
As of December 31, 2016
 
Mississippi Power
 
Southern Company
 
Southern Company
 
(in millions)
Tax positions impacting the effective tax rate
$
2

 
$
17

 
$
20

Tax positions not impacting the effective tax rate

 

 
464

Balance of unrecognized tax benefits
$
2

 
$
17

 
$
484

The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information.
Accrued interest for all tax positions was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165 in the year an abandonment is determined. The ultimate outcome of this matter cannot be determined at this time.
(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

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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 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 until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. 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

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

derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At September 30, 2017, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
 
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
 
(in millions)
 
 
 
 
Southern Company(*)
463
 
2021
 
2024
Alabama Power
66
 
2020
 
Georgia Power
159
 
2021
 
Gulf Power
28
 
2020
 
Mississippi Power
44
 
2021
 
Southern Power
13
 
2018
 
Southern Company Gas(*)
153
 
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 3.3 billion mmBtu and short natural gas positions of 3.1 billion mmBtu as of September 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 34 million mmBtu for Southern Company, 11 million mmbtu for Georgia Power and Southern Power, 5 million mmbtu for Alabama Power, 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 September 30, 2018 are $5 million for Southern Power and immaterial for all other registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize 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.

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

At September 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 September 30, 2017
 
(in millions)
 
 
 
 
 
(in millions)
Cash Flow Hedges of Existing Debt
 
 
 
 
 
 
Mississippi Power
$
900

 
1-month
LIBOR 
0.79%
March 2018
 
$
2

Fair Value Hedges of Existing Debt
 
 
 
 
 
 
Southern Company(*)
300

 
2.75%
3-month
LIBOR + 0.92%
June 2020
 

Southern Company(*)
1,500

 
2.35%
1-month
LIBOR + 0.87%
July 2021
 
(19
)
Georgia Power
250

 
5.40%
3-month
LIBOR + 4.02%
June 2018
 

Georgia Power
500

 
1.95%
3-month
LIBOR + 0.76%
December 2018
 
(2
)
Georgia Power
200

 
4.25%
3-month
LIBOR + 2.46%
December 2019
 

Southern Company Consolidated
$
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 September 30, 2018 are $(19) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses expected to be amortized into earnings through 2046.
Foreign Currency Derivatives
Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses 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.

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

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

Pay Notional
Pay Rate
Receive Notional
Receive Rate
Hedge
Maturity Date
Fair Value Gain (Loss) at September 30, 2017

(in millions)
 
(in millions)
 
 
(in millions)
Cash Flow Hedges of Existing Debt
 
 
 
 
 
Southern Power
$
677

2.95%
600

1.00%
June 2022
$
42

Southern Power
564

3.78%
500

1.85%
June 2026
38

Total
$
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 September 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.

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

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
 
As of September 30, 2017
As of December 31, 2016
Derivative Category and Balance Sheet Location
Assets
Liabilities
Assets
Liabilities
 
(in millions)
(in millions)
Southern Company
 
 
 
 
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$
21

$
25

$
73

$
27

Other deferred charges and assets/Other deferred credits and liabilities
13

23

25

33

Total derivatives designated as hedging instruments for regulatory purposes
$
34

$
48

$
98

$
60

Derivatives designated as hedging instruments in cash flow and fair value hedges
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$
8

$
6

$
23

$
7

Interest rate derivatives:
 
 
 
 
Other current assets/Other current liabilities
5

1

12

1

Other deferred charges and assets/Other deferred credits and liabilities

23

1

28

Foreign currency derivatives:
 
 
 
 
Other current assets/Other current liabilities

23


25

Other deferred charges and assets/Other deferred credits and liabilities
103



33

Total derivatives designated as hedging instruments in cash flow and fair value hedges
$
116

$
53

$
36

$
94

Derivatives not designated as hedging instruments
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$
271

$
254

$
489

$
483

Other deferred charges and assets/Other deferred credits and liabilities
115

103

66

81

Interest rate derivatives:
 
 
 
 
Other current assets/Other current liabilities


1


Total derivatives not designated as hedging instruments
$
386

$
357

$
556

$
564

Gross amounts recognized
$
536

$
458

$
690

$
718

Gross amounts offset(*)
$
(275
)
$
(351
)
$
(462
)
$
(524
)
Net amounts recognized in the Balance Sheets
$
261

$
107

$
228

$
194


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

 
As of September 30, 2017
As of December 31, 2016
Derivative Category and Balance Sheet Location
Assets
Liabilities
Assets
Liabilities
 
(in millions)
(in millions)
 
 
 
 
 
Alabama Power
 
 
 
 
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$
6

$
4

$
13

$
5

Other deferred charges and assets/Other deferred credits and liabilities
3

3

7

4

Total derivatives designated as hedging instruments for regulatory purposes
$
9

$
7

$
20

$
9

Gross amounts recognized
$
9

$
7

$
20

$
9

Gross amounts offset
$
(5
)
$
(5
)
$
(8
)
$
(8
)
Net amounts recognized in the Balance Sheets
$
4

$
2

$
12

$
1

 
 
 
 
 
Georgia Power
 
 
 
 
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$
10

$
3

$
30

$
1

Other deferred charges and assets/Other deferred credits and liabilities
8

8

14

7

Total derivatives designated as hedging instruments for regulatory purposes
$
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

$

Other deferred charges and assets/Other deferred credits and liabilities

2


3

Total derivatives designated as hedging instruments in cash flow and fair value hedges
$
1

$
3

$
2

$
3

Gross amounts recognized
$
19

$
14

$
46

$
11

Gross amounts offset
$
(10
)
$
(10
)
$
(8
)
$
(8
)
Net amounts recognized in the Balance Sheets
$
9

$
4

$
38

$
3

 
 
 
 
 
Gulf Power
 
 
 
 
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$

$
13

$
4

$
12

Other deferred charges and assets/Other deferred credits and liabilities

9

1

17

Total derivatives designated as hedging instruments for regulatory purposes
$

$
22

$
5

$
29

Gross amounts recognized
$

$
22

$
5

$
29

Gross amounts offset
$

$

$
(4
)
$
(4
)
Net amounts recognized in the Balance Sheets
$

$
22

$
1

$
25


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

 
As of September 30, 2017
As of December 31, 2016
Derivative Category and Balance Sheet Location
Assets
Liabilities
Assets
Liabilities
 
(in millions)
(in millions)
 
 
 
 
 
Mississippi Power
 
 
 
 
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$
1

$
4

$
2

$
6

Other deferred charges and assets/Other deferred credits and liabilities
2

3

2

5

Total derivatives designated as hedging instruments for regulatory purposes
$
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
$
2

$

$
2

$

Other deferred charges and assets/Other deferred credits and liabilities


1


Total derivatives designated as hedging instruments in cash flow and fair value hedges
$
2

$

$
3

$

Gross amounts recognized
$
5

$
7

$
7

$
11

Gross amounts offset
$
(3
)
$
(3
)
$
(3
)
$
(3
)
Net amounts recognized in the Balance Sheets
$
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
$
8

$
4

$
18

$
4

Foreign currency derivatives:
 
 
 
 
Other current assets/Other current liabilities

23


25

Other deferred charges and assets/Other deferred credits and liabilities
103



33

Total derivatives designated as hedging instruments in cash flow and fair value hedges
$
111

$
27

$
18

$
62

Derivatives not designated as hedging instruments
 
 
 
 
Energy-related derivatives:
 
 
 
 
Other current assets/Other current liabilities
$
1

$

$
3

$
1

Interest rate derivatives:
 
 
 
 
Other current assets/Other current liabilities


1


Total derivatives not designated as hedging instruments
$
1

$

$
4

$
1

Gross amounts recognized
$
112

$
27

$
22

$
63

Gross amounts offset
$
(1
)
$
(1
)
$
(5
)
$
(5
)
Net amounts recognized in the Balance Sheets
$
111

$
26

$
17

$
58


262

Table of Contents

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

 
As of September 30, 2017
As of December 31, 2016
Derivative Category and Balance Sheet Location
Assets
Liabilities
Assets
Liabilities
 
(in millions)
(in millions)
 
 
 
 
 
Southern Company Gas
 
 
 
 
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
Energy-related derivatives:
 
 
 
 
Assets from risk management activities/Liabilities from risk management activities-current
$
4

$
1

$
24

$
3

Other deferred charges and assets/Other deferred credits and liabilities


1


Total derivatives designated as hedging instruments for regulatory purposes
$
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

Derivatives not designated as hedging instruments
 
 
 
 
Energy-related derivatives:
 
 
 
 
Assets from risk management activities/Liabilities from risk management activities-current
$
270

$
254

$
486

$
482

Other deferred charges and assets/Other deferred credits and liabilities
115

103

66

81

Total derivatives not designated as hedging instruments
$
385

$
357

$
552

$
563

Gross amounts of recognized
$
389

$
360

$
581

$
569

Gross amounts offset(*)
$
(251
)
$
(327
)
$
(435
)
$
(497
)
Net amounts recognized in the Balance Sheets
$
138

$
33

$
146

$
72

(*)
Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76 million and $62 million as of September 30, 2017 and December 31, 2016, respectively.

263

Table of Contents

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

At September 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 September 30, 2017
Derivative Category and Balance Sheet
Location
Southern
Company(b)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(c)
 
(in millions)
 
Energy-related derivatives:
 
 
 
 
 
 
Other regulatory assets, current
$
(18
)
$
(1
)
$

$
(13
)
$
(3
)
$
(1
)
Other regulatory assets, deferred
(12
)
(1
)
(1
)
(9
)
(1
)

Other regulatory liabilities, current(a)
14

3

7



4

Other regulatory liabilities, deferred(b)
2

1

1




Total energy-related derivative gains (losses)
$
(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 September 30, 2017.
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.

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

For the three months ended September 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)
 
Statements of Income Location
Amount
 
2017
 
2016
 
 
2017
 
2016
 
(in millions)
 
 
(in millions)
Southern Company
 
 
 
 
 
 
 
 
Energy-related derivatives
$
(6
)
 
$

 
Depreciation and amortization
$
(6
)
 
$
1

Interest rate derivatives
(1
)
 
(6
)
 
Interest expense, net of amounts capitalized
(5
)
 
(6
)
Foreign currency derivatives
46

 
37

 
Interest expense, net of amounts capitalized
(5
)
 
(6
)
 
 
 
 
 
Other income (expense), net(*)
43

 
7

Total
$
39

 
$
31

 
 
$
27

 
$
(4
)
Alabama Power
 
 
 
 
 
 
 
 
Interest rate derivatives
$

 
$

 
Interest expense, net of amounts capitalized
$
(2
)
 
$
(2
)
Georgia Power
 
 
 
 
 
 
 
 
Interest rate derivatives
$

 
$

 
Interest expense, net of amounts capitalized
$
(1
)
 
$
(1
)
Mississippi Power
 
 
 
 
 
 
 
 
Interest rate derivatives
$
(1
)
 
$
(1
)
 
Interest expense, net of amounts capitalized
$

 
$

Southern Power
 
 
 
 
 
 
 
 
Energy-related derivatives
$
(6
)
 
$

 
Depreciation and amortization
$
(6
)
 
$
1

Foreign currency derivatives
46

 
37

 
Interest expense, net of amounts capitalized
(5
)
 
(6
)
 
 
 
 
 
Other income (expense), net(*)
43

 
7

Total
$
40

 
$
37

 
 
$
32

 
$
2

Southern Company Gas
 
 
 
 
 
 
 
 
Interest rate derivatives
$

 
$
(5
)
 
Interest expense, net of amounts capitalized
$

 
$

(*)
The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

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

For the nine months ended September 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)
 
Statements of Income Location
Amount
 
2017
 
2016
 
 
2017
 
2016
 
(in millions)
 
 
(in millions)
Southern Company
 
 
 
 
 
 
 
 
Energy-related derivatives
$
(26
)
 
$
(1
)
 
Depreciation and amortization
$
(12
)
 
$
1

Interest rate derivatives
(2
)
 
(189
)
 
Interest expense, net of amounts capitalized
(15
)
 
(13
)
Foreign currency derivatives
114

 
(1
)
 
Interest expense, net of amounts capitalized
(17
)
 
(7
)
 
 
 
 
 
Other income (expense), net(*)
139

 
(13
)
Total
$
86

 
$
(191
)
 
 
$
95

 
$
(32
)
Alabama Power
 
 
 
 
 
 
 
 
Interest rate derivatives
$

 
$
(3
)
 
Interest expense, net of amounts capitalized
$
(5
)
 
$
(5
)
Georgia Power
 
 
 
 
 
 
 
 
Interest rate derivatives
$

 
$

 
Interest expense, net of amounts capitalized
$
(3
)
 
$
(3
)
Gulf Power
 
 
 
 
 
 
 
 
Energy-related derivatives
$
(1
)
 
$

 
Depreciation and amortization
$

 
$

Interest rate derivatives
(1
)
 
(7
)
 
Interest expense, net of amounts capitalized

 

Total
$
(2
)
 
$
(7
)
 
 
$

 
$

Mississippi Power
 
 
 
 
 
 
 
 
Interest rate derivatives
$

 
$
(1
)
 
Interest expense, net of amounts capitalized
$
(1
)
 
$
(1
)
Southern Power
 
 
 
 
 
 
 
 
Energy-related derivatives
$
(21
)
 
$
(1
)
 
Depreciation and amortization
$
(12
)
 
$
1

Interest rate derivatives

 

 
Interest expense, net of amounts capitalized

 
(1
)
Foreign currency derivatives
114

 
(1
)
 
Interest expense, net of amounts capitalized
(17
)
 
(7
)
 


 


 
Other income (expense), net(*)
139

 
(13
)
Total
$
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.
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 nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 were as follows:
 
Gain (Loss) Recognized in OCI on Derivative
(Effective Portion)
 
 
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships
Nine Months Ended September 30, 2017
 
Statements of Income Location
Nine Months Ended September 30, 2017
 
(in millions)
 
 
(in millions)
Energy-related derivatives
$
(4
)
 
Cost of natural gas
$


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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 Location
July 1, 2016
through
September 30, 2016
 
 
January 1, 2016 through June 30, 2016
 
(in millions)
 
 
(in millions)
 
 
(in millions)
 
 
(in millions)
Energy-related derivatives
$

 
 
$

 
Cost of natural gas
$

 
 
$
(1
)
Interest rate derivatives
(5
)
 
 
(64
)
 
Interest expense, net of amounts capitalized

 
 

Total
$
(5
)
 
 
$
(64
)
 
 
$

 
 
$
(1
)
For the three and nine months ended September 30, 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 nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows:
 
 
Gain (Loss)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships
Statements of Income Location
2017
2016
 
2017
2016
 
 
(in millions)
 
(in millions)
Southern Company
 
 
 
 
 
 
Energy Related derivatives:
Natural gas revenues(*)
$
(17
)
$

 
$
48

$

 
Cost of natural gas
2

6

 
(2
)
6

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 $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.
 
 
Gain (Loss)
 
 
Successor

Successor
 
Successor
 
Successor
 
 
Predecessor
Derivatives in Non-Designated Hedging Relationships
Statements of Income Location
Three Months Ended September 30, 2017
 
Three Months Ended September 30, 2016
 
Nine Months Ended September 30, 2017
 
July 1, 2016 through September 30, 2016
 
 
January 1, 2016 through June 30, 2016
 
 
(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
 
 
 
Southern Company Gas
 
 
 
 
 
 
 
 
 
 
Energy Related derivatives:
Natural gas revenues(*)
$
(17
)
 
$

 
$
48

 
$

 
 
$
(1
)
 
Cost of natural gas
2

 
6

 
(2
)
 
6

 
 
(62
)
Total derivatives in non-designated hedging relationships
$
(15
)
 
$
6

 
$
46

 
$
6

 
 
$
(63
)
(*)
Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

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Table of Contents

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

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
Derivatives in Fair Value Hedging Relationships
 
 
Gain (Loss)
 
 
Three Months Ended September 30,
Nine Months Ended September 30,
Derivative Category
Statements of Income Location
2017
 
2016
2017
 
2016
 
 
(in millions)
(in millions)
Southern Company
 
 
 
 
 
 
 
Interest rate derivatives:
Interest expense, net of amounts capitalized
$
(5
)
 
$
(9
)
$
(6
)
 
$
15

Georgia Power
 
 
 
 
 
 
 
Interest rate derivatives:
Interest expense, net of amounts capitalized
$

 
$
(5
)
$
(1
)
 
$
10

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
At September 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 immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At September 30, 2017, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2017, cash collateral held on deposit in broker margin accounts was $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

268

Table of Contents

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

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

269

Table of Contents

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 equipment
10,108

Goodwill
5,967

Intangible assets
400

Regulatory assets
1,118

Other assets
229

Current liabilities
(2,201
)
Other liabilities
(4,742
)
Long-term debt
(4,261
)
Noncontrolling interest
(174
)
Total purchase price
$
8,001

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $565 million and $2.8 billion and net income of $15 million and $303 million for the three and nine months ended September 30, 2017, respectively, and operating revenues and net income of $543 million and $4 million, respectively, for the three months ended September 30, 2016.
The following summarized unaudited pro forma consolidated statement of earnings information assumes that the 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.

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Table of Contents

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

 
For the Nine Months Ended September 30,
 
2016
Operating revenues (in millions)
$
16,609

Net income attributable to Southern Company (in millions)
$
2,394

Basic Earnings Per Share (EPS)
$
2.52

Diluted EPS
$
2.51

These unaudited pro forma results 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 equipment
46

Intangible assets
106

Goodwill
284

Other assets
4

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.

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Table of Contents

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 Nine Months Ended September 30, 2017
During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. Acquisition-related costs were expensed as incurred and were not material.
Project Facility
Resource
Seller; Acquisition Date
Approximate Nameplate Capacity (MW)
Location
Southern Power Percentage Ownership
Actual COD
PPA Contract Period
Bethel
Wind
Invenergy,
January 6, 2017
276
Castro County, TX
100
%
 
January 2017
12 years
The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The 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 nine months ended September 30, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind.
Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of notes payable to Turner Renewable Energy, LLC.
Construction Projects Completed and in Progress
During the nine months ended September 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 September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.
Project Facility
Resource
Approximate Nameplate Capacity (MW)
Location
Actual/Expected COD
PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East Pecos
Solar
120
Pecos County, TX
March 2017
15 years
Lamesa
Solar
102
Dawson County, TX
April 2017
15 years
 
 
 
 
 
 
Projects Under Construction as of September 30, 2017
Cactus Flats(*)
Wind
148
Concho County, TX
Third quarter 2018
12-15 years
Mankato
Natural Gas
345
Mankato, MN
Second quarter 2019
20 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.

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

Development Projects
In December 2016, as part of Southern Power's renewable development strategy, one 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.

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

Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2017 and December 31, 2016 and related income from those investments for the successor three and nine month periods ended September 30, 2017, the successor three-month period ended September 30, 2016, and for the predecessor period January 1, 2016 through June 30, 2016 were as follows:
Balance Sheet Information
September 30, 2017
December 31, 2016
 
(in millions)
SNG
$
1,385

$
1,394

Atlantic Coast Pipeline
61

33

PennEast Pipeline
49

22

Triton
43

44

Pivotal JAX LNG, LLC
40

16

Horizon Pipeline
30

30

Other
1

2

Total
$
1,609

$
1,541

 
Successor
Successor
Successor
Predecessor
Income Statement Information
Three Months Ended September 30, 2017
Three Months Ended September 30, 2016
Nine Months Ended September 30, 2017
January 1, 2016 through June 30, 2016
 
(in millions)
(in millions)
(in millions)
(in millions)
SNG
$
28

$
27

$
86

$

PennEast Pipeline
1


5


Atlantic Coast Pipeline
1

1

4


Triton
1

1

3

1

Horizon Pipeline
1


2

1

Total
$
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 Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the three and nine months ended September 30, 2017 and for the period September 1, 2016 through September 30, 2016 is as follows:
Income Statement Information
Three Months Ended September 30, 2017
Nine Months Ended September 30, 2017
September 1, 2016 through September 30, 2016
 
(in millions)
Revenues
$
146

$
445

$
82

Operating income
$
71

$
218

$
60

Net income
$
57

$
172

$
55


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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 $105 million and $295 million for the three and nine months ended September 30, 2017, respectively, and $110 million and $313 million for the three and nine months ended September 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.

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

Financial data for business segments and products and services for the three and nine months ended September 30, 2017 and 2016 was as follows:
 
Electric Utilities
 
 
 
 
 
Traditional
Electric Operating
Companies
Southern
Power
Eliminations
Total
Southern Company Gas
All
Other
Eliminations
Consolidated
 
(in millions)
Three Months Ended
September 30, 2017:
 
 
 
 
 
 
 
 
Operating revenues
$
5,017

$
618

$
(112
)
$
5,523

$
565

$
153

$
(40
)
$
6,201

Segment net income (loss)(a)(b)
1,008

124


1,132

15

(80
)
2

1,069

Nine Months Ended
September 30, 2017:
 
 
 
 


 
 
 
Operating revenues
$
12,960

$
1,597

$
(318
)
$
14,239

$
2,841

$
442

$
(119
)
$
17,403

Segment net income (loss)(a)(b)(c)

276


276

303

(232
)

347

Total assets at September 30, 2017
$
73,056

$
14,648

$
(322
)
$
87,382

$
22,190

$
2,275

$
(1,532
)
$
110,315

Three Months Ended
September 30, 2016:
 
 
 
 
 
 
 
 
Operating revenues
$
5,236

$
500

$
(117
)
$
5,619

$
543

$
139

$
(37
)
$
6,264

Segment net income (loss)(a)(b)
1,022

176


1,198

4

(62
)
(1
)
1,139

Nine Months Ended
September 30, 2016:
 
 
 
 
 
 
 
 
Operating revenues
$
13,120

$
1,189

$
(330
)
$
13,979

$
543

$
311

$
(118
)
$
14,715

Segment net income (loss)(a)(b)
2,086

315


2,401

4

(146
)
(8
)
2,251

Total assets at December 31, 2016
$
72,141

$
15,169

$
(316
)
$
86,994

$
21,853

$
2,474

$
(1,624
)
$
109,697

(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 $34 million ($21 million after tax) and $88 million ($54 million after tax) for the three months ended September 30, 2017 and 2016, respectively, and $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) for the nine months ended September 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 nine months ended September 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 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


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

 
Southern Company Gas' Revenues
Period
Gas
Distribution
Operations
Gas
Marketing
Services
Other
Total
 
(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 months ended September 30, 2017 and 2016, the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 was as follows:
 
Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services(*)
Gas Midstream Operations
Total
All Other
Eliminations
Consolidated
 
(in millions)
Successor – Three Months Ended September 30, 2017:
 
 
 
 
 
 
Operating revenues
$
472

$
143

$
(24
)
$
16

$
607

$
2

$
(44
)
$
565

Segment net income
52

1

(23
)
14

44

(29
)

15

Successor – Nine Months Ended September 30, 2017:
 
 
 
 
 
 
Operating revenues
$
2,255

$
597

$
95

$
53

$
3,000

$
7

$
(166
)
$
2,841

Segment net income
223

36

28

38

325

(22
)

303

Successor – Total assets at
September 30, 2017
$
18,711

$
2,089

$
893

$
2,359

$
24,052

$
11,400

$
(13,262
)
$
22,190


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

 
Gas Distribution Operations
Gas Marketing Services
Wholesale Gas Services(*)
Gas Midstream Operations
Total
All Other
Eliminations
Consolidated
 
(in millions)
Successor – Three Months Ended September 30, 2016:
 
 
 
 
 
 
Operating revenues
$
455

$
126

$
(8
)
$
13

$
586

$
2

$
(45
)
$
543

Segment net income (loss)
27

(4
)
(11
)
14

26

(22
)

4

Predecessor – January 1, 2016 through June 30, 2016:
 
 
 
 
 
 
Operating revenues
$
1,575

$
435

$
(32
)
$
25

$
2,003

$
4

$
(102
)
$
1,905

Segment EBIT
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

(*)
The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.
 
Third Party Gross Revenues
 
Intercompany Revenues
 
Total Gross Revenues
 
Less Gross Gas Costs
 
Operating Revenues
 
(in millions)
Successor – Three Months Ended September 30, 2017
$
1,411

 
$
103

 
$
1,514

 
$
1,538

 
$
(24
)
Successor – Nine Months Ended September 30, 2017
4,781

 
362

 
5,143

 
5,048

 
95

Successor – Three Months Ended September 30, 2016
1,688

 
77

 
1,765

 
1,773

 
(8
)
Predecessor – January 1, 2016 through June 30, 2016
$
2,500

 
$
143

 
$
2,643

 
$
2,675

 
$
(32
)

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PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
Item 1A. Risk Factors.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
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 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.
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).

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On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.
On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
Additionally, on June 9, 2017, 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

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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 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.

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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, 2017
4.6

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 tax
1.5

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.
Item 6.    Exhibits.
The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.
 
 
(3) Articles of Incorporation and By-Laws
 
 
 
 
 
 
 
Alabama Power
 
 
 
 
 
 
 
(b)1
-
 
 
 
 
 

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(4) Instruments Describing Rights of Security Holders, Including Indentures
 
 
 
 
 
 
 
Georgia Power
 
 
 
 
 
 
 
(c)1
-
 
 
 
 
 
 
 
(c)2
-
 
 
 
 
 
 
 
(c)3
-
 
 
 
 
 
 
 
(10) Material Contracts
 
 
 
 
 
Mississippi Power
 
 
 
 
 
 
 
(e)1
-
 
 
 
 
 
 
 
Southern Company Gas
 
 
 
 
 
 
 
(g)1
-
 
 
 
 
 
 
 
(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)
-
 
 
 
 
 

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Table of Contents

 
 
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
-
 
 
 
 
 

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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

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Table of Contents

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

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

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Table of Contents

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

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Table of Contents

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

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Table of Contents

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

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Table of Contents

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

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Table of Contents

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


292