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GEORGIA POWER CO - Quarter Report: 2012 September (Form 10-Q)

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, 2012
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
 
 
 
 
 
333-98553
 
Southern Power Company
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
 
58-2598670


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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Registrant
 
Large
Accelerated
Filer
 
Accelerated
Filer
 
Non-
accelerated
Filer
 
Smaller
Reporting
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
 
 
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, 2012

The Southern Company
 
Par Value $5 Per Share
 
874,105,516

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
 
4,542,717

Mississippi Power Company
 
Without Par Value
 
1,121,000

Southern Power Company
 
Par Value $0.01 Per Share
 
1,000

This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. 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.

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2012


 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 3.
Item 4.

3
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INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2012


 
 
Page
    Number
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Defaults Upon Senior Securities
Inapplicable
Item 4.
Mine Safety Disclosures
Inapplicable
Item 5.
Other Information
Inapplicable
Item 6.
 


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DEFINITIONS
 
Term
Meaning
 
 
2010 ARP
Alternate Rate Plan approved by the Georgia PSC for Georgia Power, which became effective January 1, 2011 and will continue through December 31, 2013
2011 IRP Update
Georgia Power's 2011 Integrated Resource Plan update filed with the Georgia PSC on August 4, 2011
AFUDC
Allowance for funds used during construction
Alabama Power
Alabama Power Company
ARO
Asset retirement obligation
Clean Air Act
Clean Air Act Amendments of 1990
CPCN
Certificate of public convenience and necessity
CWIP
Construction work in progress
DOE
U.S. Department of Energy
DSM
Georgia Power's Demand-Side Management
ECO Plan
Mississippi Power's Environmental Compliance Overview Plan
EPA
U.S. Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
Fitch
Fitch, Inc.
Form 10-K
Combined Annual Report on Form 10-K of Southern Company,
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
and Southern Power for the year ended December 31, 2011
GAAP
Generally accepted accounting principles
Georgia Power
Georgia Power Company
Gulf Power
Gulf Power Company
IFR
Georgia Power's Interim Fuel Rider
IIC
Intercompany Interchange Contract
Internal Revenue Code
Internal Revenue Code of 1986, as amended
IRS
Internal Revenue Service
Kemper IGCC
Integrated coal gasification combined cycle facility under construction in Kemper County, Mississippi
KWH
Kilowatt-hour
LIBOR
London Interbank Offered Rate
MFF
Georgia Power's Municipal Franchise Fee
Mississippi Power
Mississippi Power Company
mmBtu
Million British thermal unit
Moody's
Moody's Investors Service, Inc.
MW
Megawatt
MWH
Megawatt-hour
NCCR
Georgia Power's Nuclear Construction Cost Recovery
NDR
Alabama Power's natural disaster reserve
NRC
Nuclear Regulatory Commission
NSR
New Source Review
OCI
Other Comprehensive Income
PEP
Mississippi Power's Performance Evaluation Plan
Plant Vogtle Units 3 and 4
Two new nuclear generating units under construction at Plant Vogtle

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Power Pool
The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA
Power Purchase Agreement
Progress Energy Carolinas
Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc., a subsidiary of Duke Energy Corporation
PSC
Public Service Commission
Qualifying Facility
A small power production facility (80 MW or less) that is a qualifying facility under the Public Utility Regulatory Policies Act of 1978
registrants
Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
ROE
Return on equity
SEC
Securities and Exchange Commission
SEGCO
Southern Electric Generating Company
SMEPA
South Mississippi Electric Power Association
Southern Company
The Southern Company
Southern Company system
Southern Company, the traditional operating companies, Southern Power, and other subsidiaries
Southern Nuclear
Southern Nuclear Operating Company, Inc.
Southern Power
Southern Power Company
S&P
Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companies
Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse
Westinghouse Electric Company LLC
wholesale revenues
revenues generated from sales for resale


6
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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 retail sales, retail rates, the strategic goals for the wholesale business, customer growth, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related estimated expenditures, access to sources of capital, projections for the qualified pension plan and other postretirement benefit plan contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other 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 legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
•
current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS and state tax audits;
•
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, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), the effects of energy conservation measures, and any potential economic impacts resulting from federal fiscal and budgetary decisions;
•
available sources and costs of fuels;
•
effects of inflation;
•
ability to control costs and avoid cost overruns during the development and construction of facilities, which includes projects involving facility designs that have not been finalized or previously constructed;
•
investment performance of Southern Company's employee benefit plans and nuclear decommissioning trust funds;
•
advances in technology;
•
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;
•
regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals, NRC actions, and potential DOE loan guarantees;
•
regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals, potential DOE loan guarantees, the SMEPA purchase decision, satisfaction of requirements to utilize investment tax credits and grants, and the outcome of any further proceedings regarding the Mississippi PSC's issuance of the CPCN;
•
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, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

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•
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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;
•
interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company's and its subsidiaries' credit ratings;
•
the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the availability or benefits of proposed DOE loan guarantees;
•
the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;
•
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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 or operation of generating resources;
•
the effect of accounting pronouncements issued periodically by standard setting bodies; and
•
other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.


8
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THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

9
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,
 
2012
 
2011
 
2012
 
2011
 
(in millions)
 
(in millions)
Operating Revenues:
 
 
 
 
 
 
 
Retail revenues
$
4,379

 
$
4,693

 
$
11,068

 
$
11,931

Wholesale revenues
497

 
557

 
1,261

 
1,513

Other electric revenues
157

 
161

 
459

 
464

Other revenues
16

 
17

 
46

 
53

Total operating revenues
5,049

 
5,428

 
12,834

 
13,961

Operating Expenses:
 
 
 
 
 
 
 
Fuel
1,553

 
1,908

 
3,907

 
5,057

Purchased power
164

 
215

 
455

 
460

Other operations and maintenance
906

 
983

 
2,817

 
2,837

MC Asset Recovery insurance settlement
—

 
—

 
(19
)
 
—

Depreciation and amortization
449

 
431

 
1,335

 
1,279

Taxes other than income taxes
237

 
239

 
690

 
686

Total operating expenses
3,309

 
3,776

 
9,185

 
10,319

Operating Income
1,740

 
1,652

 
3,649

 
3,642

Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
39

 
42

 
102

 
113

Interest expense, net of amounts capitalized
(218
)
 
(217
)
 
(649
)
 
(638
)
Other income (expense), net
1

 
(1
)
 
12

 
(3
)
Total other income and (expense)
(178
)
 
(176
)
 
(535
)
 
(528
)
Earnings Before Income Taxes
1,562

 
1,476

 
3,114

 
3,114

Income taxes
569

 
543

 
1,098

 
1,123

Consolidated Net Income
993

 
933

 
2,016

 
1,991

Dividends on Preferred and Preference Stock of Subsidiaries
17

 
17

 
49

 
49

Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries
$
976

 
$
916

 
$
1,967

 
$
1,942

Common Stock Data:
 
 
 
 
 
 
 
Earnings per share (EPS) -
 
 
 
 
 
 
 
Basic EPS
$
1.11

 
$
1.07

 
$
2.26

 
$
2.27

Diluted EPS
$
1.11

 
$
1.06

 
$
2.23

 
$
2.26

Average number of shares of common stock outstanding (in millions)
 
 
 
 
 
 
 
Basic
876

 
860

 
872

 
854

Diluted
883

 
868

 
880

 
861

Cash dividends paid per share of common stock
$
0.4900

 
$
0.4725

 
$
1.4525

 
$
1.4000

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


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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,
 
2012
 
2011
 
2012
 
2011
 
(in millions)
 
(in millions)
Consolidated Net Income
$
993

 
$
933

 
$
2,016

 
$
1,991

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Changes in fair value, net of tax of $1, $(10), $(4) and $(8), respectively
(4
)
 
(17
)
 
(11
)
 
(14
)
Reclassification adjustment for amounts included in net income, net of tax of $1, $2, $4 and $4, respectively
3

 
3

 
7

 
6

Marketable securities:
 
 
 
 
 
 
 
Change in fair value, net of tax of $-, $(2), $- and $(1), respectively
—

 
(5
)
 
—

 
(3
)
Pension and other post retirement benefit plans:
 
 
 
 
 
 
 
Reclassification adjustment for amounts included in net income, net of tax of $-, $2, $1 and $2, respectively
1

 
—

 
3

 
—

Total other comprehensive income (loss)
—

 
(19
)
 
(1
)
 
(11
)
Dividends on preferred and preference stock of subsidiaries
(17
)
 
(17
)
 
(49
)
 
(49
)
Comprehensive Income
$
976

 
$
897

 
$
1,966


$
1,931

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


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
(in millions)
Operating Activities:
 
 
 
Consolidated net income
$
2,016

 
$
1,991

Adjustments to reconcile consolidated net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
1,602

 
1,530

Deferred income taxes
645

 
914

Allowance for equity funds used during construction
(102
)
 
(113
)
Pension, postretirement, and other employee benefits
78

 
(1
)
Stock based compensation expense
45

 
35

Retail fuel cost over recovery—long-term
118

 
—

Other, net
17

 
11

Changes in certain current assets and liabilities —
 
 
 
-Receivables
(157
)
 
(118
)
-Fossil fuel stock
(232
)
 
229

-Other current assets
(5
)
 
(45
)
-Accounts payable
(240
)
 
(155
)
-Accrued taxes
311

 
440

-Accrued compensation
(142
)
 
(96
)
-Retail fuel cost over recovery—short-term
112

 
(14
)
-Other current liabilities
(22
)
 
(10
)
Net cash provided from operating activities
4,044

 
4,598

Investing Activities:
 
 
 
Property additions
(3,558
)
 
(3,115
)
Investment in restricted cash
(230
)
 
1

Distribution of restricted cash
234

 
61

Nuclear decommissioning trust fund purchases
(758
)
 
(1,946
)
Nuclear decommissioning trust fund sales
756

 
1,942

Proceeds from property sales
2

 
21

Cost of removal, net of salvage
(83
)
 
(90
)
Change in construction payables
(73
)
 
137

Other investing activities
(48
)
 
91

Net cash used for investing activities
(3,758
)
 
(2,898
)
Financing Activities:
 
 
 
Decrease in notes payable, net
(521
)
 
(1,160
)
Proceeds —
 
 
 
Long-term debt issuances
3,114

 
3,144

Interest-bearing refundable deposit related to asset sale
150

 
—

Common stock issuances
381

 
620

Redemptions —
 
 
 
Long-term debt
(2,098
)
 
(1,987
)
Common stock repurchased
(85
)
 
—

Payment of common stock dividends
(1,267
)
 
(1,193
)
Payment of dividends on preferred and preference stock of subsidiaries
(49
)
 
(49
)
Other financing activities
30

 
(6
)
Net cash provided from (used for) financing activities
(345
)
 
(631
)
Net Change in Cash and Cash Equivalents
(59
)
 
1,069

Cash and Cash Equivalents at Beginning of Period
1,315

 
447

Cash and Cash Equivalents at End of Period
$
1,256

 
$
1,516

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $62 and $54 capitalized for 2012 and 2011, respectively)
$
589

 
$
369

Income taxes, net
6

 
(358
)
Noncash transactions — accrued property additions at end of period
531

 
541

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30,
2012
 
At December 31,
2011
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
1,256

 
$
1,315

Restricted cash and cash equivalents
 
7

 
8

Receivables —
 
 
 
 
Customer accounts receivable
 
1,369

 
1,074

Unbilled revenues
 
428

 
376

Under recovered regulatory clause revenues
 
7

 
143

Other accounts and notes receivable
 
233

 
282

Accumulated provision for uncollectible accounts
 
(23
)
 
(26
)
Fossil fuel stock, at average cost
 
1,599

 
1,367

Materials and supplies, at average cost
 
931

 
903

Vacation pay
 
161

 
160

Prepaid expenses
 
519

 
385

Other regulatory assets, current
 
149

 
239

Other current assets
 
60

 
46

Total current assets
 
6,696

 
6,272

Property, Plant, and Equipment:
 
 
 
 
In service
 
61,980

 
59,744

Less accumulated depreciation
 
21,906

 
21,154

Plant in service, net of depreciation
 
40,074

 
38,590

Other utility plant, net
 
51

 
55

Nuclear fuel, at amortized cost
 
786

 
774

Construction work in progress
 
6,363

 
5,591

Total property, plant, and equipment
 
47,274

 
45,010

Other Property and Investments:
 
 
 
 
Nuclear decommissioning trusts, at fair value
 
1,281

 
1,207

Leveraged leases
 
665

 
649

Miscellaneous property and investments
 
213

 
262

Total other property and investments
 
2,159

 
2,118

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
1,389

 
1,365

Unamortized debt issuance expense
 
139

 
156

Unamortized loss on reacquired debt
 
302

 
285

Deferred under recovered regulatory clause revenues
 
27

 
48

Other regulatory assets, deferred
 
3,409

 
3,532

Other deferred charges and assets
 
568

 
481

Total deferred charges and other assets
 
5,834

 
5,867

Total Assets
 
$
61,963

 
$
59,267

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


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholders' Equity
 
At September 30,
2012
 
At December 31,
2011
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
2,433

 
$
1,717

Interest-bearing refundable deposit related to asset sale
 
150

 
—

Notes payable
 
335

 
859

Accounts payable
 
1,280

 
1,553

Customer deposits
 
366

 
347

Accrued taxes —
 
 
 
 
Accrued income taxes
 
65

 
36

Other accrued taxes
 
490

 
425

Accrued interest
 
250

 
226

Accrued vacation pay
 
205

 
205

Accrued compensation
 
325

 
450

Liabilities from risk management activities
 
105

 
209

Other regulatory liabilities, current
 
139

 
125

Other current liabilities
 
426

 
425

Total current liabilities
 
6,569

 
6,577

Long-term Debt
 
18,955

 
18,647

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
9,672

 
8,809

Deferred credits related to income taxes
 
213

 
224

Accumulated deferred investment tax credits
 
807

 
611

Employee benefit obligations
 
2,449

 
2,442

Asset retirement obligations
 
1,409

 
1,321

Other cost of removal obligations
 
1,214

 
1,165

Other regulatory liabilities, deferred
 
313

 
297

Other deferred credits and liabilities
 
641

 
514

Total deferred credits and other liabilities
 
16,718

 
15,383

Total Liabilities
 
42,242

 
40,607

Redeemable Preferred Stock of Subsidiaries
 
375

 
375

Stockholders' Equity:
 
 
 
 
Common Stockholders' Equity:
 
 
 
 
Common stock, par value $5 per share —
 
 
 
 
Authorized — 1.5 billion shares
 
 
 
 
Issued — September 30, 2012: 877 million shares
 
 
 
 
      — December 31, 2011: 866 million shares
 
 
 
 
Treasury — September 30, 2012: 3.1 million shares
 
 
 
 
          — December 31, 2011: 0.5 million shares
 
 
 
 
Par value
 
4,386

 
4,328

Paid-in capital
 
4,831

 
4,410

Treasury, at cost
 
(136
)
 
(17
)
Retained earnings
 
9,670

 
8,968

Accumulated other comprehensive loss
 
(112
)
 
(111
)
Total Common Stockholders' Equity
 
18,639

 
17,578

Preferred and Preference Stock of Subsidiaries
 
707

 
707

Total Stockholders' Equity
 
19,346

 
18,285

Total Liabilities and Stockholders' Equity
 
$
61,963

 
$
59,267

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

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

THIRD QUARTER 2012 vs. THIRD QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power and other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business of electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company's other business activities include investments in leveraged lease projects and telecommunications. For additional information on these businesses, see BUSINESS – The Southern Company System – "Traditional Operating Companies," "Southern Power," and "Other Businesses" in Item 1 of the Form 10-K.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS
Net Income 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$60
 
6.6
 
$25
 
1.3
Southern Company's third quarter 2012 net income after dividends on preferred and preference stock of subsidiaries was $976 million ($1.11 per share) compared to $916 million ($1.07 per share) for the third quarter 2011. The increase for the third quarter 2012 when compared to the corresponding period in 2011 was primarily the result of a net decrease in non-fuel operating expenses, partially offset by a net decrease in retail revenues. Retail revenues in the third quarter 2012 decreased primarily due to milder weather and a decrease in customer usage, largely offset by an increase in revenues associated with the elimination of a tax-related adjustment under Alabama Power's rate structure, an increase related to retail revenue rate effects at Georgia Power, and an increase in revenues due to increases in retail base rates at Gulf Power.
Southern Company's year-to-date 2012 net income after dividends on preferred and preference stock of subsidiaries was $1.97 billion ($2.26 per share) compared to $1.94 billion ($2.27 per share) for year-to-date 2011. The net income increase for year-to-date 2012 when compared to the corresponding period in 2011 was primarily the result of a net decrease in non-fuel operating expenses, including an insurance recovery received related to the litigation settlement with MC Asset Recovery, LLC, partially offset by a net decrease in retail revenues and lower energy revenues at Southern Power. Retail revenues for year-to-date 2012 decreased primarily due to milder weather and a decrease in customer usage, largely offset by increases in revenues associated with the elimination of a tax-related adjustment under Alabama Power's rate structure, an increase related to retail revenue rate effects at Georgia Power, an increase in revenues due to increases in retail base rates at Gulf Power, and an increase in customer growth.
 

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Retail Revenues
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(314)
 
(6.7)
 
$(863)
 
(7.2)
In the third quarter 2012, retail revenues were $4.38 billion compared to $4.69 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $11.07 billion compared to $11.93 billion for the corresponding period in 2011.
Details of the change to retail revenues were as follows: 
 
 
Third Quarter
2012
 
Year-to-Date
2012
 
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail – prior year
 
$
4,693

 
 
 
$
11,931

 
 
Estimated change in –
 
 
 
 
 
 
 
 
Rates and pricing
 
118

 
2.5

 
252

 
2.1

Sales growth (decline)
 
(33
)
 
(0.7
)
 
7

 
0.1

Weather
 
(95
)
 
(2.0
)
 
(292
)
 
(2.4
)
Fuel and other cost recovery
 
(304
)
 
(6.5
)
 
(830
)
 
(7.0
)
Retail – current year
 
$
4,379

 
(6.7
)%
 
$
11,068

 
(7.2
)%
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to the elimination of a tax-related adjustment under Alabama Power's rate structure that was effective with October 2011 billings and higher revenues due to increases in retail base rates at Gulf Power. Also contributing to the increase were increases in retail revenues at Georgia Power due to base tariff increases effective April 1, 2012 related to placing Plant McDonough-Atkinson Units 4 and 5 in service, the NCCR and demand-side management tariff increases effective January 1, 2012, as approved by the Georgia PSC, and for year-to-date 2012, the rate pricing effect of decreased customer usage. These increases at Georgia Power were partially offset by lower contributions from market-driven rates from commercial and industrial customers.
Revenues attributable to changes in sales decreased in the third quarter 2012 when compared to the corresponding period in 2011. For third quarter 2012, the decrease was due to a 2.1% decrease in weather-adjusted residential KWH sales and a 1.9% decrease in industrial KWH sales, while weather-adjusted commercial KWH sales remained flat. The decrease in weather-adjusted residential KWH sales for the third quarter 2012 was primarily due to a decrease in customer usage. The decrease in industrial KWH sales for the third quarter 2012 was primarily due to decreases in the chemical, paper, and textiles sectors, partially offset by increases in the non-manufacturing, transportation, and pipeline sectors. Revenues attributable to changes in sales remained relatively flat for all classes for year-to-date 2012 when compared to the corresponding period in 2011. While overall industrial KWH sales were relatively flat for year-to-date 2012, there were decreases in the chemical, paper, and textiles sectors, largely offset by increases in the non-manufacturing, transportation, and pipeline sectors.
Revenues resulting from changes in weather decreased $95 million in the third quarter 2012 and $292 million for year-to-date 2012 when compared to the corresponding periods in 2011 as a result of milder weather in 2012.

Fuel and other cost recovery revenues decreased $304 million in the third quarter 2012 and $830 million for year-to-date 2012 when compared to the corresponding periods in 2011. Electric rates for the traditional 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 purchased power costs, and do not affect net income.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(60)
 
(10.8)
 
$(252)
 
(16.7)
Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and 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 service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the third quarter 2012, wholesale revenues were $497 million compared to $557 million for the corresponding period in 2011, reflecting a $87 million decrease in energy revenues, partially offset by a $27 million increase in capacity revenues. The decrease in energy revenues was primarily related to a reduction in the average price of energy and lower energy sales mainly due to lower customer demand.
For year-to-date 2012, wholesale revenues were $1.26 billion compared to $1.51 billion for the corresponding period in 2011, reflecting a $300 million decrease in energy revenues, partially offset by a $48 million increase in capacity revenues. The decrease in energy revenues was primarily related to a reduction in the average price of energy and lower energy sales mainly due to lower customer demand.
Fuel and Purchased Power Expenses 
 
 
 Third Quarter 2012
vs.
Third Quarter 2011
 
Year-to-Date 2012
vs.
Year-to-Date 2011
 
 
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
Fuel
 
$
(355
)
 
(18.6
)
 
$
(1,150
)
 
(22.7
)
Purchased power
 
(51
)
 
(23.7
)
 
(5
)
 
(1.1
)
Total fuel and purchased power expenses
 
$
(406
)
 
 
 
$
(1,155
)
 
 
In the third quarter 2012, total fuel and purchased power expenses were $1.72 billion compared to $2.12 billion for the corresponding period in 2011. The decrease was primarily the result of a $281 million decrease in the average cost of fuel and purchased power, a $119 million decrease in the volume of KWHs generated, and a $6 million decrease in the volume of KWHs purchased.
For year-to-date 2012, total fuel and purchased power expenses were $4.36 billion compared to $5.52 billion for the corresponding period in 2011. The decrease was primarily the result of a $997 million decrease in the average cost of fuel and purchased power and a $552 million decrease in the volume of KWHs generated, partially offset by a $394 million increase in the volume of KWHs purchased.

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

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Details of the Southern Company system's generation and purchased power were as follows: 
 
 
Third Quarter
2012
 
Third Quarter
2011
 
Year-to-Date
2012
 
Year-to-Date
2011
Total generation (billions of KWHs)
 
50

 
53

 
133

 
147

Total purchased power (billions of KWHs)
 
5

 
5

 
14

 
8

Sources of generation (percent) —
 
 
 
 
 
 
 
 
Coal
 
43

 
54

 
40

 
54

Nuclear
 
16

 
15

 
17

 
16

Gas
 
40

 
30

 
41

 
28

Hydro
 
1

 
1

 
2

 
2

Cost of fuel, generated (cents per net KWH) —
 
 
 
 
 
 
 
 
Coal
 
4.01

 
4.14

 
4.09

 
4.06

Nuclear
 
0.86

 
0.73

 
0.83

 
0.71

Gas
 
2.94

 
4.06

 
2.76

 
4.07

Average cost of fuel, generated (cents per net KWH)
 
3.09

 
3.59

 
2.97

 
3.52

Average cost of purchased power (cents per net KWH)(a)
 
4.98

 
6.29

 
4.32

 
7.06

 
(a)
Average cost of purchased power includes fuel purchased by the electric utilities for tolling agreements where power is generated by the provider.
Fuel
In the third quarter 2012, fuel expense was $1.55 billion compared to $1.91 billion for the corresponding period in 2011. The decrease was primarily due to a 27.6% decrease in the average cost of gas per KWH generated, a higher percentage of generation from lower cost natural gas-fired resources, and lower customer demand mainly due to milder weather in 2012.
For year-to-date 2012, fuel expense was $3.91 billion compared to $5.06 billion for the corresponding period in 2011. The decrease was primarily due to a 32.2% decrease in the average cost of gas per KWH generated, a higher percentage of generation from lower cost natural gas-fired resources, and lower customer demand mainly due to milder weather in 2012.
Purchased Power
In the third quarter 2012, purchased power expense was $164 million compared to $215 million for the corresponding period in 2011. The decrease was primarily due to a 20.8% decrease in the average cost per KWH purchased.
For year-to-date 2012, purchased power expense was $455 million compared to $460 million for the corresponding period in 2011. The decrease was due to a 38.8% decrease in the average cost per KWH purchased, partially offset by a 67.4% increase in the volume of KWHs purchased as the market cost of available energy was lower than the marginal cost of generation available.
Energy purchases will vary depending on demand for energy within the Southern Company system's 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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(77)
 
(7.8)
 
$(20)
 
(0.7)
In the third quarter 2012, other operations and maintenance expenses were $906 million compared to $983 million for the corresponding period in 2011. The decrease was primarily the result of a $29 million decrease in transmission and distribution costs and a $19 million decrease related to scheduled outage and maintenance costs and commodity and labor costs, which were attributable to cost containment efforts to offset the effect of milder weather in 2012. Also contributing to the decrease were a $13 million decrease in administrative and general costs, a $13 million net decrease in customer accounts and sales related costs, and an $11 million decrease at Mississippi Power related to the expiration of an operating lease for Plant Daniel Units 3 and 4. The decrease was partially offset by an $11 million increase at Alabama Power related to the amortization of nuclear outage expenses.
For year-to-date 2012, other operations and maintenance expenses were $2.82 billion compared to $2.84 billion for the corresponding period in 2011. The decrease was primarily the result of a $50 million decrease related to scheduled outage and maintenance costs and commodity and labor costs and a $14 million decrease in distribution costs, which were attributable to cost containment efforts to offset the effect of milder weather in 2012. Also contributing to the decrease were a $32 million decrease at Mississippi Power related to the expiration of an operating lease for Plant Daniel Units 3 and 4 and a $7 million net decrease in customer accounts, sales, and customer service related costs. The decrease was partially offset by a $58 million increase in administrative and general costs primarily due to increases in pension costs and a $24 million increase at Alabama Power related to the amortization of nuclear outage expenses.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Purchase of the Plant Daniel Combined Cycle Generating Units" and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Nuclear Outage Accounting Order" of Southern Company in Item 7 of the Form 10-K for additional information.
MC Asset Recovery Insurance Settlement
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$—
 
—
 
$(19)
 
N/M
N/M – Not meaningful
In the second quarter 2012, Southern Company received an insurance recovery related to the litigation settlement with MC Asset Recovery, LLC, which resulted in income of $19 million. See Note (B) to the Condensed Financial Statements under "Insurance Recovery" herein for additional information.
Depreciation and Amortization 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$18
 
4.2
 
$56
 
4.4
In the third quarter 2012, depreciation and amortization was $449 million compared to $431 million for the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $1.34 billion compared to $1.28 billion for the corresponding period in 2011. The increases were primarily the result of an increase in depreciation due to additional plant in service related to new generation at Georgia Power's Plant McDonough-Atkinson Units 4 and 5, additional plant in service at Southern Power, as well as transmission, distribution, and environmental projects.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(3)
 
(7.1)
 
$(11)
 
(9.7)
In the third quarter 2012, AFUDC equity was $39 million compared to $42 million for the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $102 million compared to $113 million for the corresponding period in 2011. The decreases were primarily due to the completion of Georgia Power's Plant McDonough-Atkinson Units 4 and 5 in December 2011 and April 2012, respectively, partially offset by increases in CWIP related to Mississippi Power's Kemper IGCC.
Interest Expense, Net of Amounts Capitalized 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$1
 
0.5
 
$11
 
1.7
In the third quarter 2012, interest expense, net of amounts capitalized was $218 million compared to $217 million for the corresponding period in 2011. The increase when compared to the corresponding period in 2011 was not material. For year-to-date 2012, interest expense, net of amounts capitalized was $649 million compared to $638 million for the corresponding period in 2011. The increase was primarily due to a $23 million reduction in interest expense in 2011 at Georgia Power resulting from the settlement of litigation with the Georgia Department of Revenue and a net increase in interest expense related to senior notes. The increases were partially offset by a decrease related to the conclusion of certain state and federal income tax audits, a decrease in interest expense on existing variable rate pollution control revenue bonds, and an increase in capitalized interest associated with construction projects at Mississippi Power and Southern Power.
Other Income (Expense), Net 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$2
 
N/M
 
$15
 
N/M
N/M – Not meaningful
In the third quarter 2012, other income (expense), net was $1 million compared to $(1) million for the corresponding period in 2011. The increase when compared to the corresponding period in 2011 was not material. For year-to-date 2012, other income (expense), net was $12 million compared to $(3) million for the corresponding period in 2011. The increase was primarily due to the conclusion of certain federal income tax audits.
Income Taxes 
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$26
 
4.8
 
$(25)
 
(2.2)
In the third quarter 2012, income taxes were $569 million compared to $543 million for the corresponding period in 2011. The increase was primarily due to higher pre-tax earnings.
For year-to-date 2012, income taxes were $1.10 billion compared to $1.12 billion for the corresponding period in 2011. The decrease was primarily due to state income tax credits. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits" herein for additional information.



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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'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 business of selling electricity. These factors include the traditional operating companies' 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. Another major factor is the profitability of the competitive wholesale supply business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, 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 supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company 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. 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 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.
New Source Review Actions
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). The U.S. District Court for the Northern District of Alabama has not ruled on the EPA's motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.

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

Climate Change Litigation
Kivalina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. On October 8, 2012, the plaintiffs filed for review of the decision by the U.S. Court of Appeals for the Ninth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Hurricane Katrina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" of Southern Company in Item 7 of the Form 10-K for information regarding the Southern Company system's estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as the Southern Company system's preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA's final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA's proposed water and coal combustion byproducts rules.
The Southern Company system is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA's proposed water and coal combustion byproducts rules. As part of the development of its compliance strategy for the MATS rule, the Southern Company system has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from certain generating units. While the final MATS compliance plan is still being developed and the ultimate costs remain uncertain, the compliance decisions made in 2012 have allowed the Southern Company system to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $2.7 billion to approximately $1.8 billion as follows: 
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
MATS rule
 
$
150

 
$
440

 
$
1,215


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In addition, the Southern Company system has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $1.5 billion to approximately $500 million over the 2012 through 2014 period based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows: 
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
Proposed water and coal combustion byproducts rules
 
$
10

 
$
85

 
$
405

While the Southern Company system's ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, the Southern Company system estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $13 billion to $18 billion range provided in the Form 10-K. Included in this amount is approximately $750 million that is also included in the 2012 through 2014 base level capital investment of the traditional operating companies described in the Form 10-K in anticipation of these rules.
The Southern Company system's ultimate compliance strategy and actual future environmental capital expenditures are dependent on development of the final MATS compliance plan and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time.
As part of SEGCO's environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Alabama Power and Georgia Power. The capacity of SEGCO's units is sold to Alabama Power and Georgia Power through a PPA. The impact of SEGCO's ultimate compliance strategy on the PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Southern Company's financial statements.
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 on the eight-hour ozone and fine particulate matter air quality standards, the MATS rule, the Cross-State Air Pollution Rule (CSAPR), and the Clean Air Visibility Rule (CAVR).
On May 21, 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. The only area within the traditional operating companies' service territory designated as a nonattainment area was a 15-county area within metropolitan Atlanta. The potential impact of the revised standard and nonattainment designation will depend on further evaluation and implementation by the Georgia Environmental Protection Division and cannot be determined at this time.

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On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within the Southern Company system's service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
On August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety and directed the EPA to continue to administer the Clean Air Interstate Rule pending the EPA's development of a valid replacement. The vacatur of CSAPR creates additional uncertainty with respect to whether additional controls may be required for CAVR and best available retrofit technology compliance. On October 5, 2012, the EPA filed for review of the decision by the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter depends on the outcome of any legal challenges and further action by the EPA and cannot be determined at this time.
On August 29, 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized, the revisions would apply the NSPS to all new, reconstructed, and modified CTs, including CTs at combined cycle units, during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and 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 on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Byproducts
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Southern Company in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. The ultimate outcome of these matters cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA's actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
PSC Matters
Retail Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. The traditional operating companies have experienced lower pricing for natural gas resulting in an increase in natural gas generation and a decrease in coal generation, which is currently more costly. The lower cost of natural gas has resulted in total over recovered fuel costs at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power included in Southern Company's Condensed Balance Sheet herein of approximately $282 million at September 30, 2012. At December 31, 2011, total under recovered fuel costs at Alabama Power and Georgia Power included in Southern Company's Condensed Balance Sheet herein were approximately $169 million, and Gulf Power and Mississippi Power had a total over recovered fuel balance included in Southern Company's Condensed Balance Sheet herein of approximately $52 million. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect annual cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances.
On June 21, 2012, the Georgia PSC approved a decrease in Georgia Power's fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.
As of September 30, 2012, Georgia Power's fuel cost over recovery balance totaled $199 million. This balance is slightly below the $200 million required to automatically trigger the Georgia PSC's approved IFR adjustment mechanism. On November 1, 2012, Georgia Power filed a request with the Georgia PSC to voluntarily trigger the IFR early and reduce fuel cost recovery rates effective January 1, 2013. The requested reduction would reduce annual billings by approximately $122 million. In accordance with the IFR process, the Georgia PSC will have 30 days to consider Georgia Power's request. The ultimate outcome of this matter cannot be determined at this time.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

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Alabama Power
Rate CNP
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate CNP" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power's under recovered Rate CNP balance as of September 30, 2012 was $14 million as compared to $6 million at December 31, 2011. Alabama Power's under recovered Rate CNP Environmental balance as of September 30, 2012 was $12 million as compared to $11 million at December 31, 2011. These under recovered balances at September 30, 2012 are included in deferred under recovered regulatory clause revenues on Southern Company's Condensed Balance Sheet herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.
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 September 17, 2012, the Alabama PSC approved and certificated the remaining PPA for the purchase of approximately 200 MWs of the approximately 400 MWs of energy from wind-powered generating facilities and all associated environmental attributes, including renewable energy credits. The terms of this PPA and the previously approved and certificated PPA permit Alabama Power to use the energy and retire the associated environmental attributes in service of its customers or to sell environmental attributes, separately or bundled with energy, to third parties.
Natural Disaster Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Natural Disaster Reserve" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve" in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At September 30, 2012, the NDR had an accumulated balance of $102 million as compared to $110 million at December 31, 2011, which are included in Southern Company's Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Southern Company's Condensed Statement of Income herein.
Compliance and Pension Cost Accounting Order
On November 6, 2012, the Alabama PSC approved an accounting order for certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. Under the accounting order, expenses from January 2013 through December 2017 related to compliance with standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation and cyber security requirements issued by the NRC will be deferred to a regulatory asset account and amortized over a three-year period beginning in January 2015. Expenses from January 2013 through December 2017 related to compliance with NRC guidance addressing the readiness at nuclear facilities within the U.S., as prompted by the earthquake and tsunami that struck Japan in 2011, also will be deferred as a regulatory asset and recovered over the same amortization period. The compliance-related expenses to be afforded regulatory asset treatment over the five-year period are currently estimated to be approximately $43 million. See "Other Matters" herein for information regarding the NRC's guidance issued as a result of the earthquake and tsunami that struck Japan in 2011. In addition, the accounting order authorizes Alabama Power

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to defer an incremental increase in its pension cost for 2013. The increased pension cost is estimated to be approximately $17 million. During 2013, the actual incremental increase will be deferred to a regulatory asset account and will be amortized over a three-year period beginning in January 2015. Pursuant to the accounting order, Alabama Power has the ability to accelerate the amortization of the regulatory assets.
Alabama Power expects that the accounting order and other cost containment measures will preclude a need for a rate adjustment under Rate RSE.
Georgia Power
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information on Georgia Power's 2010 ARP.
In accordance with the terms of the 2010 ARP, on November 1, 2012, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective on January 1, 2013:
•
Increase the DSM tariffs by approximately $16 million;
•
Increase the traditional base tariffs by approximately $58 million to recover the revenue requirements for Plant McDonough-Atkinson Units 4, 5, and 6 for the period through December 31, 2013, which also reflects a separate settlement agreement associated with the June 30, 2011 quarterly construction monitoring report for Plant McDonough-Atkinson (see Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Other Construction" in Item 8 of the Form 10-K for additional information); and
•
Increase the MFF tariff, consistent with the adjustments above, as well as those related to the IFR and NCCR tariff adjustments described under "Retail Fuel Cost Recovery" and Note B to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein.
2011 Integrated Resource Plan Update
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality," "– Water Quality," and "– Coal Combustion Byproducts" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Rate Plans" and "– 2011 Integrated Resource Plan Update" in Item 8 of the Form 10-K for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia's Multi-Pollutant Rule; Georgia Power's analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; the 2010 ARP; and the 2011 IRP Update.
On March 20, 2012, the Georgia PSC approved Georgia Power's request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Power's 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.

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Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Southern Company through 2013. Due to the significant amount of estimated bonus depreciation for 2012, a portion of Southern Company's tax credit utilization will be deferred. Consequently, Southern Company's positive cash flow benefit is estimated to be between $775 million and $860 million in 2012.
Construction Program
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 generating facilities, including the ongoing construction of natural gas and solar units at Southern Power, Plant Vogtle Units 3 and 4 at Georgia Power, and the Kemper IGCC at Mississippi Power, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements of Southern Company under "Construction Program" in Item 8 of the Form 10-K for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction," "Retail Regulatory Matters – Georgia Power – Other Construction," and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Investments in Leveraged Leases
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Investments in Leveraged Leases" of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information.
The recent financial and operational performance of one of Southern Company's lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the assets. Current projections indicate significant uncertainty as to whether the lessee will be able to pay the December 2012 semi-annual rent payment in full. Southern Company continues to be engaged in discussions with the lessee and the holders of the project's nonrecourse debt to restructure the debt payments and the related rental payments to allow additional capital investment in the project to be made to improve the operation of the generation assets and the financial viability of the lease transaction. Southern Company continues to believe there is a reasonable possibility that it will be able to reach an agreement with the lessee and the debtholders to restructure the project prior to the end of 2012. However, due to continued poor performance of the generation assets and the uncertainties surrounding the receipt of the December 2012 semi-annual rent payment and its ability to successfully restructure the project, Southern Company has placed the lease on nonaccrual status whereby,

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effective July 2012, income associated with this investment is not recognized in the financial statements. If the attempts at restructuring the project are unsuccessful and the project is ultimately abandoned, the potential impairment loss that would be incurred is approximately $90 million on an after-tax basis. If the restructuring is successfully completed prior to the end of 2012, Southern Company will be required to record a reduction in leveraged lease income of up to approximately $20 million in the fourth quarter 2012. 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 increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, 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 the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, including the one in use at Plant Hatch, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. On August 29, 2012, the NRC staff issued the final interim staff guidance document, which offers acceptable approaches to meeting the requirements of the NRC's orders before the December 31, 2016 compliance deadline. The interim staff guidance is not mandatory, but licensees would be required to obtain NRC approval for taking an approach other than as outlined in the interim staff guidance. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the NRC and 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. The ultimate outcome of these events cannot be determined at this time.
See "PSC Matters – Alabama Power – Compliance and Pension Cost Accounting Order" herein for additional information on Alabama Power's PSC approved accounting order, which allows the deferral of certain compliance-related operations and maintenance expenditures related to compliance with the NRC guidance.

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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 Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
Alabama Power and Georgia Power are now using automated meter readings to measure unbilled KWH sales for energy delivered through month end. Increased usage of actual data to compute unbilled revenues reduces the impact that estimates could have on Southern Company's results of operations; therefore, Southern Company no longer considers unbilled revenues a critical accounting estimate.
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, 2012. Southern Company 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 "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
Net cash provided from operating activities totaled $4.0 billion for the first nine months of 2012, a decrease of $554 million from the corresponding period in 2011. The decrease in net cash provided from operating activities was primarily due to an increase in fossil fuel stock as a result of milder weather in the first nine months of 2012 and lower natural gas prices and a decrease in accrued taxes due to the timing of tax payments. Net cash used for investing activities totaled $3.8 billion for the first nine months of 2012 primarily due to property additions to utility plant. Net cash used for financing activities totaled $345 million for the first nine months of 2012. This was primarily due to redemptions of long-term debt, the repurchase of common stock, and payments of common stock dividends, offset by issuances of long-term debt. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2012 include an increase of $2.3 billion in total property, plant, and equipment for the construction of generation, transmission, and distribution facilities. Other significant changes include an increase in deferred income taxes of $863 million due to bonus depreciation and an increase in equity of $1.1 billion.
The market price of Southern Company's common stock at the end of the third quarter 2012 was $46.09 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $21.32 per share, representing a market-to-book ratio of 216%, compared to $46.29, $20.32, and 228%, respectively, at the end of 2011. The dividend for the third quarter 2012 was $0.49 per share compared to $0.4725 per share in the third quarter 2011.

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Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of 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 to comply with existing environmental regulations, and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $2.4 billion will be required through September 30, 2013 to fund maturities and announced redemptions of long-term debt.
See FUTURE EARNINGS POTENTIAL – "Environmental Statutes and Regulations – General" herein for a description of the Southern Company system's estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
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 generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet new regulatory requirements; changes in FERC rules and regulations; 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
Southern Company intends to meet its future capital needs through internal cash flow 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 to be raised will be contingent on Southern Company's investment opportunities.
Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan 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, security issuances, term loans, short-term borrowings, 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 Company in Item 7 of the Form 10-K for additional information.
In June 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs, or approximately $3.46 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.

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In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees for Mississippi Power. In the event that the DOE does not issue a conditional commitment or a final definitive loan guarantee, Mississippi Power expects to finance the construction of the Kemper IGCC through traditional capital markets financings. Mississippi Power also received DOE Clean Coal Power Initiative Round 2 (CCPI2) grant funds of $245 million that were used for the construction of the Kemper IGCC. An additional $25 million in CCPI2 grant funds is expected to be received for the initial operation of the Kemper IGCC.
Southern Company'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 cash needs, which can fluctuate significantly due to the seasonality of the business of the Southern Company system. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.
At September 30, 2012, Southern Company and its subsidiaries had approximately $1.3 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2012, including expiration dates, were as follows:
 
 
Expires
 
 
 
Executable Term
Loans
 
Due Within One
Year(a)
Company
 
2012
 
2013
 
2014
and
Beyond(b) 
 
Total
 
Unused
 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
 
 
(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
Southern Company
 
$
—

 
$
—

 
$
1,000

 
$
1,000

 
$
1,000

 
$
—

 
$
—

 
$
—

 
$
—

Alabama Power
 
—

 
157

 
1,150

 
1,307

 
1,307

 
55

 
—

 
55

 
102

Georgia Power
 
—

 
—

 
1,750

 
1,750

 
1,740

 
—

 
—

 
—

 
—

Gulf Power
 
20

 
60

 
195

 
275

 
275

 
45

 
—

 
45

 
35

Mississippi Power
 
16

 
120

 
165

 
301

 
301

 
25

 
41

 
66

 
70

Southern Power
 
—

 
—

 
500

 
500

 
500

 
—

 
—

 
—

 
—

Other
 
—

 
50

 
—

 
50

 
50

 
25

 
—

 
25

 
25

Total
 
$
36

 
$
387

 
$
4,760

 
$
5,183

 
$
5,173

 
$
150

 
$
41

 
$
191

 
$
232

(a)
Reflects facilities expiring on or before September 30, 2013.
(b)
All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014.
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.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants.
A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2012 was approximately $1.8 billion.
The traditional operating companies 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 each of the traditional operating companies.

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Details of short-term borrowings were as follows:
 
 
Short-term Debt at September 30, 2012
 
Short-term Debt During the Period(a)
 
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
 
(in millions)
 
 
 
(in millions)
 
 
 
(in millions)
Commercial paper
 
$
329

 
0.3
%
 
$
463

 
0.3
%
 
$
592

(a) Average and maximum amounts are based upon daily balances during the three month period ended September 30, 2012.
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Southern Company 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 of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. The maximum potential collateral requirements under these contracts at September 30, 2012 were as follows:
 
Credit Ratings
  Maximum Potential  
Collateral
Requirements
 
(in millions)
At BBB and Baa2
$
9

At BBB- and/or Baa3
635

Below BBB- and/or Baa3
2,583

On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 9.967% per annum at September 30, 2012, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company's ability to access capital markets, particularly the short-term debt market.

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Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk
Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. Southern Company may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, Southern Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Company's policies in areas such as counterparty exposure and risk management practices. Southern 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.
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. Southern Company had no material change in market risk exposure for the third quarter 2012 when compared with the December 31, 2011 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2012 were as follows:
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(170
)
 
$
(231
)
Contracts realized or settled
 
56

 
184

Current period changes(a)
 
51

 
(16
)
Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(63
)
 
$
(63
)
 (a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

34
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and nine months ended September 30, 2012 were as follows:
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
83

 
$
142

Natural gas options
 
24

 
27

Other energy-related derivatives
 
—

 
(1
)
Total changes
 
$
107

 
$
168

The net hedge volumes of energy-related derivative contracts were as follows:
 
 
September 30,
2012
 
June 30,
2012
 
December 31,
2011
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
158

 
141

 
123

Commodity – Natural gas options
 
111

 
101

 
66

Total hedge volume
 
269

 
242

 
189

The weighted average swap contract cost above market prices was approximately $0.33 per mmBtu as of September 30, 2012, $0.95 per mmBtu as of June 30, 2012, and $1.51 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the natural gas hedge gains and losses are recovered through the traditional operating companies' fuel cost recovery clauses.
The net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:
Asset (Liability) Derivatives
 
September 30,
2012
 
December 31,
2011
 
 
(in millions)
Regulatory hedges
 
$
(63
)
 
$
(221
)
Cash flow hedges
 
(1
)
 
(1
)
Not designated
 
1

 
(9
)
Total fair value
 
$
(63
)
 
$
(231
)
Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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.
Total net unrealized pre-tax gains recognized in income for the three and nine months ended September 30, 2012 were $5 million and $9 million, respectively, and were not material for the corresponding periods in 2011.

35
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2012 were as follows:
 
 
September 30, 2012
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(63
)
 
(54
)
 
(12
)
 
3

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(63
)
 
$
(54
)
 
$
(12
)
 
$
3

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Company. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Southern Company and its subsidiaries and their derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Southern Company does not expect the impact of these rules to be material.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company in Item 7 and Note 1 under "Financial Instruments" and Note 11 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
During the first nine months of 2012, Southern Company issued approximately 11.6 million shares of common stock for $381 million through employee and director stock plans. Since mid-2011, Southern Company has issued additional equity only through its employee and director stock plans. In July 2012, Southern Company announced a program to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. Under this program, approximately 2.6 million shares have been repurchased through September 30, 2012 at a total cost of $117 million. Pursuant to Board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, in accordance with applicable securities laws.
In addition, Southern Company is not currently issuing shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by the independent plan administrators.

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Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the debt financing activities during the first nine months of 2012:
Company
 
Senior Note
Issuances
 
Senior Note
Redemptions
and Maturities
 
Pollution
Control Bond
Issuances
 
Pollution
Control Bond
Redemptions
 
Other
Long-Term
Debt Issuances
 
Other Long-
Term Debt
Redemptions
and Maturities
 
 
 
 
(in millions)
 
 
 
 
Southern Company
 
$
—

 
$
500

 
$
—

 
$
—

 
$
—

 
$
—

Alabama Power
 
250

 
250

 
—

 
1

 
—

 
—

Georgia Power
 
1,900

 
550

 
234

 
234

 
—

 
250

Gulf Power
 
100

 
91

 
—

 
—

 
—

 
—

Mississippi Power
 
600

 
90

 
—

 
—

 
26

 
115

Southern Power
 
—

 
—

 
—

 
—

 
5

 
1

Total
 
$
2,850

 
$
1,481

 
$
234

 
$
235

 
$
31

 
$
366

Southern Company's subsidiaries used the proceeds of the debt issuances shown in the table above for the redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their respective continuous construction programs.
On January 17, 2012, Southern Company's $500 million aggregate principal amount of Series 2007A 5.30% Senior Notes matured.
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 9.967% per annum at September 30, 2012, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies.
In August 2012, the Mississippi Business Finance Corporation entered into an agreement to issue up to $42.5 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012A (Mississippi Power Company Project), up to $21.25 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012B (Mississippi Power Company Project), and up to $21.25 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012C (Mississippi Power Company Project) for the benefit of Mississippi Power. As reflected in the table above, in August 2012, the Mississippi Business Finance Corporation issued $4.36 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012B and $21.25 million aggregate principal amount of Revenue Bonds (Mississippi Power Company Project), Series 2012C for the benefit of Mississippi Power. The proceeds were  used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of these bonds will be used for this same purpose.
Subsequent to September 30, 2012, Alabama Power issued $400 million aggregate principal amount of Series 2012B 0.550% Senior Notes due October 15, 2015. The proceeds were used to redeem, in October 2012, $200 million aggregate principal amount of Series 2007C 6.00% Senior Insured Monthly Notes due October 15, 2037 and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to September 30, 2012, Georgia Power announced the redemption that will occur in December 2012 of $100 million aggregate principal amount of its Series 2007F 6.05% Senior Monthly Notes due December 1, 2038.

37
Table of Contents
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

38
Table of Contents


PART I
Item 3. Quantitative And Qualitative Disclosures About Market Risk.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for each registrant 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 and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see 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, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power 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). 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.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power's 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) during the third quarter 2012 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, or Southern Power's internal control over financial reporting.

39
Table of Contents


ALABAMA POWER COMPANY

40
Table of Contents


ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in millions)
 
(in millions)
Operating Revenues:
 
 
 
 
 
 
 
Retail revenues
$
1,476

 
$
1,489

 
$
3,822

 
$
3,859

Wholesale revenues, non-affiliates
79

 
80

 
210

 
218

Wholesale revenues, affiliates
31

 
52

 
51

 
202

Other revenues
51

 
50

 
147

 
152

Total operating revenues
1,637

 
1,671

 
4,230

 
4,431

Operating Expenses:
 
 
 
 
 
 
 
Fuel
469

 
512

 
1,118

 
1,335

Purchased power, non-affiliates
31

 
34

 
63

 
62

Purchased power, affiliates
41

 
49

 
147

 
152

Other operations and maintenance
307

 
309

 
944

 
896

Depreciation and amortization
161

 
160

 
478

 
476

Taxes other than income taxes
84

 
84

 
255

 
254

Total operating expenses
1,093

 
1,148

 
3,005

 
3,175

Operating Income
544

 
523

 
1,225

 
1,256

Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
4

 
7

 
13

 
18

Interest income
4

 
4

 
12

 
13

Interest expense, net of amounts capitalized
(71
)
 
(73
)
 
(217
)
 
(224
)
Other income (expense), net
(7
)
 
(7
)
 
(18
)
 
(20
)
Total other income and (expense)
(70
)
 
(69
)
 
(210
)
 
(213
)
Earnings Before Income Taxes
474

 
454

 
1,015

 
1,043

Income taxes
184

 
180

 
394

 
407

Net Income
290

 
274

 
621

 
636

Dividends on Preferred and Preference Stock
10

 
10

 
30

 
30

Net Income After Dividends on Preferred and Preference Stock
$
280

 
$
264

 
$
591

 
$
606


CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in millions)
 
(in millions)
Net Income After Dividends on Preferred and Preference Stock
$
280

 
$
264

 
$
591

 
$
606

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Changes in fair value, net of tax of $(2), $(4), $(6) and $(3), respectively
(2
)
 
(8
)
 
(9
)
 
(5
)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $- and $(1), respectively
—

 
—

 
—

 
(2
)
Total other comprehensive income (loss)
(2
)
 
(8
)
 
(9
)
 
(7
)
Comprehensive Income
$
278

 
$
256

 
$
582

 
$
599

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

41
Table of Contents


ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
(in millions)
Operating Activities:
 
 
 
Net income
$
621

 
$
636

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
574

 
562

Deferred income taxes
132

 
350

Allowance for equity funds used during construction
(13
)
 
(18
)
Pension, postretirement, and other employee benefits
10

 
(17
)
Stock based compensation expense
7

 
5

Other, net
(3
)
 
6

Changes in certain current assets and liabilities —
 
 
 
-Receivables
(83
)
 
(74
)
-Fossil fuel stock
(93
)
 
75

-Materials and supplies
(5
)
 
(13
)
-Other current assets
(1
)
 
(19
)
-Accounts payable
(167
)
 
(120
)
-Accrued taxes
146

 
215

-Accrued compensation
(27
)
 
(35
)
-Other current liabilities
(13
)
 
5

Net cash provided from operating activities
1,085

 
1,558

Investing Activities:
 
 
 
Property additions
(616
)
 
(694
)
Distribution of restricted cash from pollution control revenue bonds
—

 
11

Nuclear decommissioning trust fund purchases
(128
)
 
(301
)
Nuclear decommissioning trust fund sales
128

 
301

Cost of removal, net of salvage
(17
)
 
(52
)
Change in construction payables
(2
)
 
(13
)
Other investing activities
(11
)
 
14

Net cash used for investing activities
(646
)
 
(734
)
Financing Activities:
 
 
 
Proceeds —
 
 
 
Capital contributions from parent company
22

 
10

Senior notes issuances
250

 
700

Redemptions —
 
 
 
Pollution control revenue bonds
(1
)
 
(4
)
Senior notes
(250
)
 
(650
)
Payment of preferred and preference stock dividends
(30
)
 
(30
)
Payment of common stock dividends
(404
)
 
(415
)
Other financing activities
(4
)
 
(13
)
Net cash used for financing activities
(417
)
 
(402
)
Net Change in Cash and Cash Equivalents
22

 
422

Cash and Cash Equivalents at Beginning of Period
344

 
154

Cash and Cash Equivalents at End of Period
$
366

 
$
576

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $5 and $7 capitalized for 2012 and 2011, respectively)
$
203

 
$
207

Income taxes, net
172

 
(95
)
Noncash transactions—accrued property additions at end of period
16

 
15

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

42
Table of Contents


ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30,
2012
 
At December 31,
2011
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
366

 
$
344

Restricted cash and cash equivalents
 
—

 
1

Receivables —
 
 
 
 
Customer accounts receivable
 
446

 
332

Unbilled revenues
 
121

 
126

Other accounts and notes receivable
 
59

 
35

Affiliated companies
 
43

 
79

Accumulated provision for uncollectible accounts
 
(9
)
 
(10
)
Fossil fuel stock, at average cost
 
437

 
344

Materials and supplies, at average cost
 
379

 
375

Vacation pay
 
59

 
59

Prepaid expenses
 
106

 
74

Other regulatory assets, current
 
21

 
44

Other current assets
 
11

 
11

Total current assets
 
2,039

 
1,814

Property, Plant, and Equipment:
 
 
 
 
In service
 
21,253

 
20,809

Less accumulated provision for depreciation
 
7,659

 
7,344

Plant in service, net of depreciation
 
13,594

 
13,465

Nuclear fuel, at amortized cost
 
328

 
330

Construction work in progress
 
381

 
374

Total property, plant, and equipment
 
14,303

 
14,169

Other Property and Investments:
 
 
 
 
Equity investments in unconsolidated subsidiaries
 
53

 
62

Nuclear decommissioning trusts, at fair value
 
597

 
540

Miscellaneous property and investments
 
74

 
73

Total other property and investments
 
724

 
675

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
528

 
532

Prepaid pension costs
 
82

 
59

Deferred under recovered regulatory clause revenues
 
27

 
48

Other regulatory assets, deferred
 
965

 
994

Other deferred charges and assets
 
158

 
186

Total deferred charges and other assets
 
1,760

 
1,819

Total Assets
 
$
18,826

 
$
18,477

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


43
Table of Contents


ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity
 
At September 30,
2012
 
At December 31,
2011
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
700

 
$
500

Accounts payable —
 
 
 
 
Affiliated
 
183

 
203

Other
 
178

 
322

Customer deposits
 
86

 
85

Accrued taxes —
 
 
 
 
Accrued income taxes
 
93

 
32

Other accrued taxes
 
104

 
34

Accrued interest
 
66

 
63

Accrued vacation pay
 
48

 
48

Accrued compensation
 
71

 
95

Liabilities from risk management activities
 
46

 
54

Other regulatory liabilities, current
 
5

 
18

Other current liabilities
 
37

 
38

Total current liabilities
 
1,617

 
1,492

Long-term Debt
 
5,430

 
5,632

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
3,366

 
3,257

Deferred credits related to income taxes
 
80

 
83

Accumulated deferred investment tax credits
 
143

 
149

Employee benefit obligations
 
356

 
343

Asset retirement obligations
 
580

 
553

Other cost of removal obligations
 
751

 
703

Other regulatory liabilities, deferred
 
185

 
156

Other deferred credits and liabilities
 
75

 
82

Total deferred credits and other liabilities
 
5,536

 
5,326

Total Liabilities
 
12,583

 
12,450

Redeemable Preferred Stock
 
342

 
342

Preference Stock
 
343

 
343

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
 
2,220

 
2,182

Retained earnings
 
2,143

 
1,956

Accumulated other comprehensive loss
 
(27
)
 
(18
)
Total common stockholder's equity
 
5,558

 
5,342

Total Liabilities and Stockholder's Equity
 
$
18,826

 
$
18,477

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

44
Table of Contents
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



THIRD QUARTER 2012 vs. THIRD QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within 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 selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. 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. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$16
 
6.1
 
$(15)
 
(2.5)
Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2012 was $280 million compared to $264 million for the corresponding period in 2011. The increase for the third quarter 2012 when compared to the corresponding period in 2011 was related to an increase in revenues associated with the elimination of a tax-related adjustment under Alabama Power's rate structure, increases in industrial energy sales, and decreases in other operations and maintenance expenses, partially offset by decreases in weather-related revenues due to milder weather in the third quarter 2012 when compared to the corresponding period in 2011.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2012 was $591 million compared to $606 million for the corresponding period in 2011. The decrease for year-to-date 2012 when compared to the corresponding period in 2011 was related to decreases in weather-related revenues due to milder weather, increases in other operations and maintenance expenses, and a decrease in AFUDC equity in 2012. These decreases were partially offset by increases in revenues associated with the elimination of a tax-related adjustment under Alabama Power's rate structure and increases in energy sales. See BUSINESS – "Rate Matters – Rate Structure and Cost Recovery Plans" of Alabama Power in Item 1 and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Rate Adjustments" of Alabama Power in Item 7 of the Form 10-K for information regarding the rate structure of Alabama Power.

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



Retail Revenues
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(13)
 
(0.9)
 
$(37)
 
(1.0)
In the third quarter 2012, retail revenues were $1.48 billion compared to $1.49 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $3.82 billion compared to $3.86 billion for the corresponding period in 2011.
Details of the change to retail revenues were as follows:
 
 
Third Quarter
2012
 
Year-to-Date
2012
 
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail – prior year
 
$
1,489

 
 
 
$
3,859

 
 
Estimated change in –
 
 
 
 
 
 
 
 
Rates and pricing
 
40

 
2.7

 
96

 
2.5

Sales growth (decline)
 
5

 
0.3

 
49

 
1.3

Weather
 
(27
)
 
(1.8
)
 
(114
)
 
(3.0
)
Fuel and other cost recovery
 
(31
)
 
(2.1
)
 
(68
)
 
(1.8
)
Retail – current year
 
$
1,476

 
(0.9
)%
 
$
3,822

 
(1.0
)%
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to the elimination of a tax-related adjustment under Alabama Power's rate structure that was effective with October 2011 billings, slightly offset by decreased revenues associated with Rate Certificated New Plant Environmental (Rate CNP Environmental).
Revenues attributable to changes in sales increased in the third quarter 2012 when compared to the corresponding period in 2011. Industrial KWH energy sales increased 0.3% due to an increase in usage resulting from changes in production levels primarily in the pipelines, automotive and plastics, and stone, clay, and glass sectors, offset by decreases in the primary metals, forest products, and textiles sectors. The changes in weather-adjusted residential and commercial KWH energy sales were not material.
Revenues attributable to changes in sales increased year-to-date 2012 when compared to the corresponding period in 2011. Weather-adjusted residential and commercial KWH energy sales increased 2.1% and 1.0%, respectively, as a result of increases in usage. Industrial KWH energy sales increased 1.9% due to an increase in usage resulting from changes in production levels primarily in the primary metals, pipelines, automotive and plastics, and forest products sectors, partially offset by decreases in the textiles, stone, clay, and glass, and water and sewer sectors.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Alabama Power's service territory experienced milder weather conditions in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011. The resulting decreases for the third quarter 2012 were 2.9% and 1.7% for residential and commercial sales revenue, respectively. The resulting decreases for year-to-date 2012 were 5.4% and 1.9% for residential and commercial sales revenue, respectively.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to lower fuel costs associated with decreased KWH generation and lower average cost per KWH generated due to lower natural gas prices. 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 NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.

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



See BUSINESS – "Rate Matters – Rate Structure and Cost Recovery Plans" of Alabama Power in Item 1, MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Rate Adjustments" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
 Wholesale Revenues - Non-Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(1)
 
(1.3)
 
$(8)
 
(3.7)
Wholesale revenues from sales to non-affiliates will vary depending on the market prices of available wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the third quarter 2012, the decrease in wholesale revenues from non-affiliates was not material. For year-to-date 2012, wholesale revenues from non-affiliates were $210 million compared to $218 million for the corresponding period in 2011. The decrease was primarily due to a 2.3% decrease in KWH sales and a 1.3% decrease in the price of energy.
Wholesale Revenues – Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(21)
 
(40.4)
 
$(151)
 
(74.8)
Wholesale revenues from sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
In the third quarter 2012, wholesale revenues from affiliates were $31 million compared to $52 million for the corresponding period in 2011. The decrease was primarily due to a 27.0% decrease in KWH sales and a 19.2% decrease in the price of energy.
For year-to-date 2012, wholesale revenues from affiliates were $51 million compared to $202 million for the corresponding period in 2011. The decrease was primarily due to a 70.0% decrease in KWH sales and a 16.4% decrease in the price of energy.

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



Fuel and Purchased Power Expenses

 
Third Quarter 2012
vs.
Third Quarter 2011
 
Year-to-Date 2012
vs.
Year-to-Date 2011
 
 
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
Fuel
 
$
(43
)
 
(8.4)
 
$
(217
)
 
(16.3)
Purchased power – non-affiliates
 
(3
)
 
(8.8)
 
1

 
1.6
Purchased power – affiliates
 
(8
)
 
(16.3)
 
(5
)
 
(3.3)
Total fuel and purchased power expenses
 
$
(54
)
 
 
 
$
(221
)
 
 
In the third quarter 2012, total fuel and purchased power expenses were $541 million compared to $595 million for the corresponding period in 2011. The decrease was primarily due to a $21 million decrease related to a reduction in total KWHs generated as a result of milder weather in the third quarter 2012, a $16 million decrease in the cost of fuel, a $12 million decrease in the average cost of purchased power, and a $4 million decrease in KWHs purchased.
For year-to-date 2012, total fuel and purchased power expenses were $1.33 billion compared to $1.55 billion for the corresponding period in 2011. The decrease was primarily due to a $176 million decrease related to a reduction in total KWHs generated as a result of milder weather for year-to-date 2012, a $69 million decrease in the average cost of purchased power, and a $36 million decrease in the cost of fuel, partially offset by a $59 million increase in KWHs purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's Energy Cost Recovery Rate mechanism. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Fuel Cost Recovery" herein for additional information.
Details of Alabama Power's generation and purchased power were as follows:
 
 
Third Quarter
2012
 
Third Quarter
2011
 
Year-to-Date
2012
 
Year-to-Date
2011
Total generation (billions of KWHs)
 
17

 
18

 
44

 
50

Total purchased power (billions of KWHs)
 
1

 
1

 
5

 
4

Sources of generation (percent) –
 
 
 
 
 
 
 
 
Coal
 
59

 
61

 
52

 
57

Nuclear
 
22

 
22

 
24

 
22

Gas
 
17

 
15

 
19

 
16

Hydro
 
2

 
2

 
5

 
5

Cost of fuel, generated (cents per net KWH) –
 
 
 
 
 
 
 
 
Coal
 
3.40

 
3.39

 
3.38

 
3.18

Nuclear
 
0.82

 
0.64

 
0.79

 
0.65

Gas
 
3.17

 
4.05

 
2.98

 
4.13

Average cost of fuel, generated (cents per net KWH)(a)
 
2.77

 
2.89

 
2.63

 
2.75

Average cost of purchased power (cents per net KWH)(b)
 
6.04

 
6.97

 
4.67

 
6.14

(a)
KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)
Average cost of purchased power includes fuel purchased by Alabama Power for tolling agreements where power is generated by the provider.

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



Fuel
In the third quarter 2012, fuel expense was $469 million compared to $512 million for the corresponding period in 2011. The $43 million decrease was due to a 21.7% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements, and a 6.2% decrease in KWHs generated by coal, slightly offset by a 1.5% increase in KWHs generated by natural gas.
For year-to-date 2012, fuel expense was $1.12 billion compared to $1.34 billion for the corresponding period in 2011. The $217 million decrease was due to a 27.9% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements, and a 20.8% decrease in KWHs generated by coal, slightly offset by a 6.0% increase in KWHs generated by natural gas.
Purchased Power – Non-Affiliates
In the third quarter 2012, purchased power expense from non-affiliates was $31 million compared to $34 million for the corresponding period in 2011. The decrease was related to a 34.8% decrease in the average cost per KWH, partially offset by a 25.2% increase in the amount of energy purchased.
For year-to-date 2012, purchased power expense from non-affiliates was $63 million compared to $62 million for the corresponding period in 2011. The increase was related to a 129.6% increase in the amount of energy purchased, partially offset by a 58.8% decrease in the average cost per KWH.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2012, purchased power expense from affiliates was $41 million compared to $49 million for the corresponding period in 2011. The decrease was related to a 13.9% decrease in the amount of energy purchased and a 2.6% decrease in the average cost per KWH.
For year-to-date 2012, purchased power expense from affiliates was $147 million compared to $152 million for the corresponding period in 2011. The decrease was related to a 13.5% decrease in the average cost per KWH, partially offset by an 11.4% increase in the amount of energy purchased.
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 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(2)
 
(0.6)
 
$48
 
5.4
In the third quarter 2012, the decrease in other operations and maintenance expenses was not material. For year-to-date 2012, other operations and maintenance expenses were $944 million compared to $896 million for the corresponding period in 2011. Administrative and general expenses increased $32 million primarily due to pension and other benefit-related expenses and property insurance expenses. Nuclear production expenses increased $10 million primarily due to the amortization of nuclear outage expenses of $24 million, partially offset by a decrease in operation costs related to decreases in labor. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Nuclear Outage Accounting Order" of Alabama Power in Item 7 of the Form 10-K for additional information.

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



Allowance for Funds Used During Construction
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(3)
 
(42.9)
 
$(5)
 
(27.8)
In the third quarter 2012, AFUDC equity was $4 million compared to $7 million for the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $13 million compared to $18 million for the corresponding period in 2011. These decreases were primarily due to decreases in capital expenditures for nuclear facility and general plant projects.
Income Taxes
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$4
 
2.2
 
$(13)
 
(3.2)
In the third quarter 2012, the increase in income taxes was not material. For year-to-date 2012, income taxes were $394 million compared to $407 million for the corresponding period in 2011. The decrease for year-to-date 2012 was primarily due to lower pre-tax earnings as a result of lower revenues due to milder weather and an increase in operations and maintenance expense.
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 selling electricity. 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. Future earnings in the near term will depend, in part, upon maintaining energy sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced 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. Changes in economic conditions impact sales for Alabama Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
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. 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.

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



New Source Review Actions
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA's motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.
Climate Change Litigation
Kivalina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. On October 8, 2012, the plaintiffs filed for review of the decision by the U.S. Court of Appeals for the Ninth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Hurricane Katrina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for information regarding Alabama Power's estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Alabama Power's estimates for environmental compliance investments associated with complying with the EPA's final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA's proposed water and coal combustion byproducts rules.

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



Alabama Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA's proposed water and coal combustion byproducts rules. As part of the development of its compliance strategy for the MATS rule, Alabama Power has entered into agreements for the construction of baghouses on generating units with an aggregate capacity of 1,901 MWs and plans to utilize additional compliance strategies at other units with an aggregate capacity of 4,678 MWs including utilizing existing or additional natural gas capability and/or using additives or other injection technologies. Certain transmission system upgrades may also be required. While the final MATS compliance plan is still being developed and the ultimate costs remain uncertain, the compliance decisions made in 2012 have allowed Alabama Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $1.2 billion to approximately $585 million as follows:
 
 
2012
 
2013
 
2014
 
 
(in millions)
MATS rule
 
$
55

 
$
180

 
$
350

In addition, Alabama Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $630 million to approximately $175 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:
 
 
2012
 
2013
 
2014
 
 
(in millions)
Proposed water and coal combustion byproducts rules
 
$
5

 
$
10

 
$
160

While Alabama Power's ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Alabama Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $5 billion to $7 billion range provided in the Form 10-K.
Alabama Power's ultimate compliance strategy and actual future environmental capital expenditures are dependent on development of the final MATS compliance plan and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Alabama Power's fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time.
As part of SEGCO's environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Alabama Power and Georgia Power. The capacity of SEGCO's units is sold to Alabama Power and Georgia Power through a PPA. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information. The impact of SEGCO's ultimate compliance strategy on the PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Alabama Power's financial statements.

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



Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards, the MATS rule, the Cross-State Air Pollution Rule (CSAPR), and the Clean Air Visibility Rule (CAVR).
On May 21, 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Alabama Power's service territory were designated as nonattainment areas.
On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Alabama Power's service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Alabama Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
On August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety and directed the EPA to continue to administer the Clean Air Interstate Rule pending the EPA's development of a valid replacement. The vacatur of CSAPR creates additional uncertainty with respect to whether additional controls may be required for CAVR and best available retrofit technology compliance. On October 5, 2012, the EPA filed for review of the decision by the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter depends on the outcome of any legal challenges and further action by the EPA and cannot be determined at this time.
On August 29, 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized, the revisions would apply the NSPS to all new, reconstructed, and modified CTs, including CTs at combined cycle units, during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and 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 Alabama Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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Coal Combustion Byproducts
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Alabama Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. 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 April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA's actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
PSC Matters
Rate CNP
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Rate Adjustments – Rate CNP" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate CNP Environmental. Alabama Power's under recovered Rate CNP balance as of September 30, 2012 was $14 million as compared to $6 million at December 31, 2011. Alabama Power's under recovered Rate CNP Environmental balance as of September 30, 2012 was $12 million as compared to $11 million at December 31, 2011. These under recovered balances at September 30, 2012 are included in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheet herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.
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 September 17, 2012, the Alabama PSC approved and certificated the remaining PPA for the purchase of approximately 200 MWs of the approximately 400 MWs of energy from wind-powered generating facilities and all associated environmental attributes, including renewable energy credits. The terms of this PPA and the previously approved and certificated PPA permit Alabama Power to use the energy and retire the associated environmental attributes in service of its customers or to sell environmental attributes, separately or bundled with energy, to third parties. 

54
Table of Contents
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Retail Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Alabama Power's fuel cost recovery. Alabama Power's over recovered fuel costs as of September 30, 2012 totaled $1 million as compared to a $31 million under recovered balance at December 31, 2011. The over recovered fuel costs at September 30, 2012 are included in other regulatory liabilities, current and the under recovered fuel costs at December 31, 2011 are included in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheets herein. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.
Natural Disaster Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Natural Disaster Reserve" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Natural Disaster Reserve" in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At September 30, 2012, the NDR had an accumulated balance of $102 million, which is included in Alabama Power's Condensed Balance Sheet herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Alabama Power's Condensed Statement of Income herein.
Compliance and Pension Cost Accounting Order
On November 6, 2012, the Alabama PSC approved an accounting order for certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. Under the accounting order, expenses from January 2013 through December 2017 related to compliance with standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation and cyber security requirements issued by the NRC will be deferred to a regulatory asset account and amortized over a three-year period beginning in January 2015. Expenses from January 2013 through December 2017 related to compliance with NRC guidance addressing the readiness at nuclear facilities within the U.S., as prompted by the earthquake and tsunami that struck Japan in 2011, also will be deferred as a regulatory asset and recovered over the same amortization period. The compliance-related expenses to be afforded regulatory asset treatment over the five-year period are currently estimated to be approximately $43 million. See "Other Matters" herein for information regarding the NRC's guidance issued as a result of the earthquake and tsunami that struck Japan in 2011. In addition, the accounting order authorizes Alabama Power to defer an incremental increase in its pension cost for 2013. The increased pension cost is estimated to be approximately $17 million. During 2013, the actual incremental increase will be deferred to a regulatory asset account and will be amortized over a three-year period beginning in January 2015. Pursuant to the accounting order, Alabama Power has the ability to accelerate the amortization of the regulatory assets.
Alabama Power expects that the accounting order and other cost containment measures will preclude a need for a rate adjustment under Rate RSE.

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



Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Alabama Power through 2013. Consequently, Alabama Power's positive cash flow benefit is estimated to be between $105 million and $120 million in 2012.
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 increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, 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 the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. On August 29, 2012, the NRC staff issued the final interim staff guidance document, which offers acceptable approaches to meeting the requirements of the NRC's orders before the December 31, 2016 compliance deadline. The interim staff guidance is not mandatory, but licensees would be required to obtain NRC approval for taking an approach other than as outlined in the interim staff guidance. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. See RISK FACTORS of Alabama Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.
See "PSC Matters – Compliance and Pension Cost Accounting Order" herein for additional information on Alabama Power's PSC approved accounting order, which allows the deferral of certain compliance-related operations and maintenance expenditures related to compliance with the NRC guidance.


56
Table of Contents
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 Electric Utility Regulation, Contingent Obligations, and Pension and Other Postretirement Benefits.
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, 2012. 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 "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
Net cash provided from operating activities totaled $1.1 billion for the first nine months of 2012, a decrease of $473 million as compared to the first nine months of 2011. The decrease in cash provided from operating activities was primarily due to an increase in fossil fuel stock, a decrease in deferred income taxes, and the timing of income tax payments and refunds associated with bonus depreciation. Net cash used for investing activities totaled $646 million for the first nine months of 2012 primarily due to gross property additions related to nuclear fuel and transmission, distribution, and steam generating equipment. Net cash used for financing activities totaled $417 million for the first nine months of 2012. This was primarily due to the payment of common stock dividends.
Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2012 include increases of $200 million of securities due within one year, $187 million in retained earnings, $134 million in property, plant, and equipment associated with routine property additions, $114 million in customer accounts receivable due to seasonal variations in customer usage, $109 million in accumulated deferred income taxes related to bonus depreciation, and $93 million in fossil fuel stock, at average cost, and decreases of $202 million in long-term debt and $144 million in other accounts payable associated with the timing of property tax payments.
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 regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $700 million will be required through September 30, 2013 to fund maturities and announced redemptions of long-term debt.

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



Alabama Power's updated construction program for 2013 and 2014 includes anticipated costs for MATS compliance but does not include the potential incremental compliance cost estimates for the proposed water and coal combustion byproducts rules. Alabama Power's updated base level construction program and the potential incremental environmental compliance estimates for the proposed water and coal combustion byproducts rules (based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) for 2013 and 2014 are as follows:
 
2013
2014
Construction program:
(in millions)
Base capital
$
954

$
1,117

Existing environmental statutes and regulations, including MATS
195

424

Total construction program base level capital investment
$
1,149

$
1,541

 
 
 
Potential incremental environmental compliance investment:
 
 
Proposed water and coal combustion byproducts rules
$
10

$
160

See FUTURE EARNINGS POTENTIAL – "Environmental Statutes and Regulations – General" herein for additional information on Alabama Power's estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
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 units, to meet new 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 required for construction and other purposes from sources similar to those utilized in the past. Alabama Power has primarily utilized funds from operating cash flows, short-term debt, security issuances, 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 Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of Alabama Power's debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.
At September 30, 2012, Alabama Power had approximately $366 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2012, including expiration dates, were as follows:
Expires
 
 
 
 
 
Executable Term
Loans
 
Due Within One
Year(a) 
2012
 
2013
 
2014
and
Beyond

 
Total
 
Unused
 
One
Year

 
Two
Years

 
Term
Out

 
No Term
Out

(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
$
—

 
$
157

 
$
1,150

 
$
1,307

 
$
1,307

 
$
55

 
$
—

 
$
55

 
$
102

(a)
Reflects facilities expiring on or before September 30, 2013.

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



See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Alabama Power. Alabama Power is currently in compliance with all such covenants. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Alabama Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2012 was approximately $793 million.
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 operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
During the three months ended September 30, 2012, Alabama Power had no commercial paper or other short-term debt outstanding.
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Alabama 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 below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At September 30, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $291 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant 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, any credit rating downgrade could impact Alabama Power's ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Alabama Power's market risk exposure relative to interest rate changes for the third quarter 2012 has not changed materially compared to the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power had no material change in market risk exposure for the third quarter 2012 when compared with the December 31, 2011 reporting period.

59
Table of Contents
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and nine months ended September 30, 2012 were as follows:
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(32
)
 
$
(48
)
Contracts realized or settled
 
12

 
41

Current period changes(a)
 
12

 
(1
)
Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(8
)
 
$
(8
)
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and nine months ended September 30, 2012 were as follows:
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
19

 
$
33

Natural gas options
 
5

 
7

Total changes
 
$
24

 
$
40

The net hedge volumes of energy-related derivative contracts were as follows:
 
 
September 30,
2012
 
June 30,
2012
 
December 31,
2011
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
41

 
32

 
30

Commodity – Natural gas options
 
14

 
11

 
9

Total hedge volume
 
55

 
43

 
39

The weighted average swap contract cost above market prices was approximately $0.25 per mmBtu as of September 30, 2012, $0.93 per mmBtu as of June 30, 2012, and $1.45 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. A majority of the natural gas hedge gains and losses is recovered through Alabama Power's retail fuel cost recovery clause.
Regulatory hedges relate to Alabama Power's fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Alabama Power's fuel cost recovery clause.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.

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



Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2012 were as follows:
 
 
September 30, 2012
Fair Value Measurements
 
 
Total
Fair Value
 
Maturity
 
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(8
)
 
(11
)
 
3

 
—

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(8
)
 
$
(11
)
 
$
3

 
$
—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Alabama Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Alabama Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Alabama Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Alabama Power in Item 7 and Note 1 under "Financial Instruments" and Note 11 to the financial statements of Alabama Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In January 2012, Alabama Power issued $250 million aggregate principal amount of Series 2012A 4.10% Senior Notes due January 15, 2042. The proceeds were used for general corporate purposes, including Alabama Power's continuous construction program. Alabama Power settled $100 million of interest rate swaps related to this issuance at a loss of $1 million. The loss is being amortized to interest expense, in earnings, over 10 years.
In March 2012, Alabama Power redeemed approximately $1 million aggregate principal amount of The Industrial Development Board of the Town of West Jefferson Solid Waste Disposal Revenue Bonds (Alabama Power Company Miller Plant Project), Series 2008.
In April 2012, Alabama Power redeemed $250 million aggregate principal amount of its Series 2007B 5.875% Senior Notes due April 1, 2047.
Subsequent to September 30, 2012, Alabama Power issued $400 million aggregate principal amount of Series 2012B 0.550% Senior Notes due October 15, 2015. The proceeds were used to redeem, on October 15, 2012, $200 million aggregate principal amount of Series 2007C 6.00% Senior Insured Monthly Notes due October 15, 2037 and for general corporate purposes, including Alabama Power's continuous construction program.
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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Table of Contents


GEORGIA POWER COMPANY

62
Table of Contents


GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in millions)
 
(in millions)
Operating Revenues:
 
 
 
 
 
 
 
Retail revenues
$
2,335

 
$
2,609

 
$
5,786

 
$
6,494

Wholesale revenues, non-affiliates
73

 
90

 
214

 
270

Wholesale revenues, affiliates
5

 
4

 
14

 
31

Other revenues
85

 
85

 
249

 
247

Total operating revenues
2,498

 
2,788

 
6,263

 
7,042

Operating Expenses:
 
 
 
 
 
 
 
Fuel
630

 
838

 
1,642

 
2,299

Purchased power, non-affiliates
79

 
127

 
266

 
297

Purchased power, affiliates
181

 
193

 
469

 
513

Other operations and maintenance
398

 
453

 
1,243

 
1,294

Depreciation and amortization
186

 
180

 
559

 
531

Taxes other than income taxes
100

 
102

 
281

 
283

Total operating expenses
1,574

 
1,893

 
4,460

 
5,217

Operating Income
924

 
895

 
1,803

 
1,825

Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
15

 
26

 
41

 
73

Interest expense, net of amounts capitalized
(95
)
 
(90
)
 
(276
)
 
(257
)
Other income (expense), net
(1
)
 
(4
)
 
(10
)
 
(10
)
Total other income and (expense)
(81
)
 
(68
)
 
(245
)
 
(194
)
Earnings Before Income Taxes
843

 
827

 
1,558

 
1,631

Income taxes
314

 
303

 
558

 
583

Net Income
529

 
524

 
1,000

 
1,048

Dividends on Preferred and Preference Stock
4

 
4

 
13

 
13

Net Income After Dividends on Preferred and Preference Stock
$
525

 
$
520

 
$
987

 
$
1,035

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in millions)
 
(in millions)
Net Income After Dividends on Preferred and Preference Stock
$
525

 
$
520

 
$
987

 
$
1,035

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
$
526

 
$
521

 
$
989

 
$
1,037

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,
 
2012
 
2011
 
(in millions)
Operating Activities:
 
 
 
Net income
$
1,000

 
$
1,048

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
684

 
646

Deferred income taxes
243

 
422

Allowance for equity funds used during construction
(41
)
 
(73
)
Retail fuel cost over recovery—long-term
118

 
—

Deferred expenses
(20
)
 
(30
)
Other, net
23

 
(38
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
(23
)
 
(68
)
-Fossil fuel stock
(126
)
 
115

-Prepaid income taxes
40

 
81

-Other current assets
4

 
(2
)
-Accounts payable
(57
)
 
(46
)
-Accrued taxes
40

 
(1
)
-Accrued compensation
(43
)
 
(18
)
-Retail fuel cost over recovery—short-term
81

 
—

-Other current liabilities
48

 
43

Net cash provided from operating activities
1,971

 
2,079

Investing Activities:
 
 
 
Property additions
(1,291
)
 
(1,363
)
Investment of restricted cash
(234
)
 
—

Distribution of restricted cash
234

 
—

Nuclear decommissioning trust fund purchases
(630
)
 
(1,645
)
Nuclear decommissioning trust fund sales
628

 
1,641

Cost of removal, net of salvage
(42
)
 
(21
)
Change in construction payables, net of joint owner portion
(141
)
 
108

Other investing activities
9

 
(9
)
Net cash used for investing activities
(1,467
)
 
(1,289
)
Financing Activities:
 
 
 
Decrease in notes payable, net
(513
)
 
(575
)
Proceeds —
 
 
 
Capital contributions from parent company
29

 
199

Pollution control revenue bonds issuances
234

 
604

Senior notes issuances
1,900

 
550

Other long-term debt issuances
—

 
250

Redemptions —
 
 
 
Pollution control revenue bonds
(234
)
 
(286
)
Senior notes
(550
)
 
(277
)
Other long-term debt
(250
)
 
(509
)
Payment of preferred and preference stock dividends
(13
)
 
(13
)
Payment of common stock dividends
(681
)
 
(672
)
Other financing activities
(14
)
 
(3
)
Net cash provided from (used for) financing activities
(92
)
 
(732
)
Net Change in Cash and Cash Equivalents
412

 
58

Cash and Cash Equivalents at Beginning of Period
13

 
8

Cash and Cash Equivalents at End of Period
$
425

 
$
66

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $17 and $27 capitalized for 2012 and 2011, respectively)
$
237

 
$
240

Income taxes, net
186

 
(2
)
Noncash transactions—accrued property additions at end of period
253

 
375

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,
2012
 
At December 31,
2011
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
425

 
$
13

Receivables —
 
 
 
 
Customer accounts receivable
 
713

 
571

Unbilled revenues
 
224

 
172

Under recovered regulatory clause revenues
 
—

 
137

Joint owner accounts receivable
 
48

 
87

Other accounts and notes receivable
 
54

 
61

Affiliated companies
 
28

 
26

Accumulated provision for uncollectible accounts
 
(11
)
 
(13
)
Fossil fuel stock, at average cost
 
849

 
723

Materials and supplies, at average cost
 
403

 
406

Vacation pay
 
84

 
82

Prepaid income taxes
 
122

 
71

Other regulatory assets, current
 
68

 
108

Other current assets
 
111

 
106

Total current assets
 
3,118

 
2,550

Property, Plant, and Equipment:
 
 
 
 
In service
 
28,667

 
27,804

Less accumulated provision for depreciation
 
10,537

 
10,296

Plant in service, net of depreciation
 
18,130

 
17,508

Other utility plant, net
 
51

 
55

Nuclear fuel, at amortized cost
 
458

 
443

Construction work in progress
 
3,342

 
3,274

Total property, plant, and equipment
 
21,981

 
21,280

Other Property and Investments:
 
 
 
 
Equity investments in unconsolidated subsidiaries
 
45

 
63

Nuclear decommissioning trusts, at fair value
 
684

 
667

Miscellaneous property and investments
 
44

 
44

Total other property and investments
 
773

 
774

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
760

 
756

Other regulatory assets, deferred
 
1,534

 
1,604

Other deferred charges and assets
 
255

 
187

Total deferred charges and other assets
 
2,549

 
2,547

Total Assets
 
$
28,421

 
$
27,151

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,
2012
 
At December 31,
2011
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
1,455

 
$
455

Notes payable
 
2

 
515

Accounts payable —
 
 
 
 
Affiliated
 
378

 
337

Other
 
441

 
686

Customer deposits
 
230

 
213

Accrued taxes —
 
 
 
 
Accrued income taxes
 
134

 
50

Other accrued taxes
 
269

 
304

Accrued interest
 
117

 
92

Accrued vacation pay
 
60

 
60

Accrued compensation
 
87

 
125

Liabilities from risk management activities
 
31

 
68

Other regulatory liabilities, current
 
75

 
65

Over recovered regulatory clause revenues, current
 
81

 
—

Other current liabilities
 
131

 
171

Total current liabilities
 
3,491

 
3,141

Long-term Debt
 
8,121

 
8,018

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
4,737

 
4,388

Deferred credits related to income taxes
 
116

 
122

Accumulated deferred investment tax credits
 
211

 
220

Employee benefit obligations
 
922

 
905

Asset retirement obligations
 
773

 
734

Other cost of removal obligations
 
94

 
110

Other deferred credits and liabilities
 
311

 
224

Total deferred credits and other liabilities
 
7,164

 
6,703

Total Liabilities
 
18,776

 
17,862

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
 
5,570

 
5,522

Retained earnings
 
3,418

 
3,112

Accumulated other comprehensive loss
 
(7
)
 
(9
)
Total common stockholder's equity
 
9,379

 
9,023

Total Liabilities and Stockholder's Equity
 
$
28,421

 
$
27,151

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 2012 vs. THIRD QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity 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 selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, and fuel. In addition, Georgia Power is currently constructing two new nuclear units. 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. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$5
 
1.0
 
$(48)
 
(4.6)
Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2012 was $525 million compared to $520 million for the corresponding period in 2011. The increase was primarily due to lower non-fuel operating expenses largely offset by lower retail revenues, as well as lower AFUDC and higher income taxes. Retail revenues in the third quarter 2012 decreased primarily due to milder weather and a decrease in customer usage, partially offset by an increase related to retail revenue rate effects.
Georgia Power's net income after dividends on preferred and preference stock for year-to-date 2012 was $987 million compared to $1.04 billion for the corresponding period in 2011. The decrease was primarily due to lower operating revenues primarily as a result of milder weather and a decrease in customer usage, as well as lower AFUDC, higher interest expense reflecting a 2011 litigation settlement, and higher depreciation and amortization. These income reductions were partially offset by retail revenue rate effects, lower operations and maintenance expenses, and lower income taxes.
Retail Revenues
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(274)
 
(10.5)
 
$(708)
 
(10.9)
In the third quarter 2012, retail revenues were $2.34 billion compared to $2.61 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $5.79 billion compared to $6.49 billion for the corresponding period in 2011.

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



Details of the change to retail revenues were as follows:
 
 
Third Quarter
2012
 
Year-to-Date
2012
 
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail – prior year
 
$
2,609

 
 
 
$
6,494

 
 
Estimated change in –
 
 
 
 
 
 
 
 
Rates and pricing
 
60

 
2.3

 
108

 
1.7

Sales growth (decline)
 
(39
)
 
(1.5
)
 
(44
)
 
(0.7
)
Weather
 
(64
)
 
(2.4
)
 
(157
)
 
(2.4
)
Fuel cost recovery
 
(231
)
 
(8.9
)
 
(615
)
 
(9.5
)
Retail – current year
 
$
2,335

 
(10.5
)%
 
$
5,786

 
(10.9
)%
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to base tariff increases effective April 1, 2012 related to placing Plant McDonough-Atkinson Units 4 and 5 in service, the NCCR and demand-side management tariff increases effective January 1, 2012, as approved by the Georgia PSC, and, for year-to-date 2012, the rate pricing effect of decreased customer usage. These increases were partially offset by lower contributions from market-driven rates from commercial and industrial customers.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Weather-adjusted residential KWH sales decreased 4.0%, weather-adjusted commercial KWH sales decreased 0.2%, and weather-adjusted industrial KWH sales decreased 1.7% in the third quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted residential KWH sales decreased 1.3%, weather-adjusted commercial KWH sales decreased 0.5%, and weather-adjusted industrial KWH sales decreased 1.0% for year-to-date 2012 when compared to the corresponding period in 2011. Georgia Power had an increase of over 12,000 new residential customers in 2012. However, weather-adjusted usage per residential customer decreased 4.5% and 1.9% in the third quarter and year-to-date 2012, respectively. In addition to the continued impact of the sluggish economy, Georgia Power implemented five residential and two commercial energy efficiency programs in 2011. Participation in these programs has continued to increase and has reduced residential and commercial KWH energy sales by approximately 0.2% and 0.3%, respectively, for year-to-date 2012 when compared to the corresponding period in 2011.
Revenues resulting from changes in weather decreased in the third quarter 2012 when compared to the corresponding period in 2011 due to milder weather in 2012. Revenues resulting from changes in weather decreased year-to-date 2012 when compared to the corresponding period in 2011 as a result of milder weather in 2012 and cold weather in January 2011.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $231 million and $615 million in the third quarter and year-to-date 2012, respectively, when compared to the corresponding periods in 2011 due to both lower demand, as discussed above, and lower costs primarily due to lower natural gas prices.
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, including the energy component of purchased power costs, and do not affect net income. Georgia Power lowered fuel rates effective June 1, 2012 and has filed a request with the Georgia PSC to further lower fuel rates effective January 1, 2013. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.


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


Wholesale Revenues – Non-Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(17)
 
(18.9)
 
$(56)
 
(20.7)
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
In the third quarter 2012, wholesale revenues from non-affiliates were $73 million compared to $90 million in the corresponding period in 2011. For year-to-date 2012, wholesale revenues from non-affiliates were $214 million compared to $270 million in the corresponding period in 2011. The decreases were primarily due to 24.2% and 32.7% decreases in KWH sales in the third quarter and year-to-date 2012, respectively, due to lower demand resulting from milder weather and the availability of market energy at a lower cost than Georgia Power-owned generation.
Wholesale Revenues – Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$1
 
25.0
 
$(17)
 
(54.8)
Wholesale revenues from sales to affiliated companies within the Southern Company system 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 energy is generally sold at marginal cost.
In the third quarter 2012 and 2011, wholesale revenues from affiliates were immaterial. For year-to-date 2012, wholesale revenues from affiliates were $14 million compared to $31 million in the corresponding period in 2011. The decrease was primarily due to a 31.3% decrease in KWH sales due to lower demand resulting from milder weather in 2012 and the availability of market energy at a lower cost than Georgia Power-owned generation.
Fuel and Purchased Power Expenses 
 
 
Third Quarter 2012
vs.
Third Quarter 2011
 
Year-to-Date 2012
vs.
Year-to-Date 2011
 
 
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
Fuel
 
$
(208
)
 
(24.8
)
 
$
(657
)
 
(28.6
)
Purchased power — non-affiliates
 
(48
)
 
(37.8
)
 
(31
)
 
(10.4
)
Purchased power — affiliates
 
(12
)
 
(6.2
)
 
(44
)
 
(8.6
)
Total fuel and purchased power expenses
 
$
(268
)
 
 
 
$
(732
)
 
 


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


In the third quarter 2012, total fuel and purchased power expenses were $890 million compared to $1.16 billion in the corresponding period in 2011. For year-to-date 2012, total fuel and purchased power expenses were $2.38 billion compared to $3.11 billion for the corresponding period in 2011. The decreases were primarily due to the lower cost of natural gas used for generation and lower demand related to milder weather in 2012.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Georgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.
Details of Georgia Power's generation and purchased power were as follows:
 
 
Third Quarter
2012
 
Third Quarter
2011
 
Year-to-Date
2012
 
Year-to-Date
2011
Total generation (billions of KWHs)
 
17

 
19

 
46

 
53

Total purchased power (billions of KWHs)
 
8

 
8

 
22

 
19

Sources of generation (percent) —
 
 
 
 
 
 
 
 
Coal
 
45

 
66

 
44

 
65

Nuclear
 
23

 
21

 
26

 
22

Gas
 
32

 
12

 
29

 
12

Hydro
 
—

 
1

 
1

 
1

Cost of fuel, generated (cents per net KWH) —
 
 
 
 
 
 
 
 
Coal
 
4.56

 
4.74

 
4.74

 
4.73

Nuclear
 
0.89

 
0.81

 
0.86

 
0.76

Gas
 
3.00

 
5.48

 
2.94

 
5.10

Average cost of fuel, generated (cents per net KWH)
 
3.21

 
3.99

 
3.19

 
3.90

Average cost of purchased power (cents per net KWH)(a)
 
4.45

 
5.51

 
4.18

 
5.61

(a)
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 2012, fuel expense was $630 million compared to $838 million in the corresponding period in 2011. The decrease was primarily due to a 6.3% decrease in KWHs generated as a result of lower KWH demand and a 19.6% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.
For year-to-date 2012, fuel expense was $1.64 billion compared to $2.30 billion in the corresponding period in 2011. The decrease was primarily due to a 12.3% decrease in KWHs generated as a result of lower KWH demand and an 18.2% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.
Purchased Power – Non-Affiliates
In the third quarter 2012, purchased power expense from non-affiliates was $79 million compared to $127 million in the corresponding period in 2011. The decrease was due to a 21.8% decrease in the volume of KWHs purchased and a decrease of 14.0% in the average cost per KWH purchased primarily due to lower natural gas prices.
For year-to-date 2012, purchased power expense from non-affiliates was $266 million compared to $297 million in the corresponding period in 2011. The decrease was due to a decrease of 30.4% in the average cost per KWH purchased primarily due to lower natural gas prices, partially offset by a 30.3% increase in the volume of KWHs purchased as the market cost of available energy was lower than the additional Georgia Power-owned generation available.

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


Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2012, purchased power expense from affiliates was $181 million compared to $193 million in the corresponding period in 2011. The decrease was due to an 18.8% decrease in the average cost per KWH purchased, reflecting lower natural gas prices, partially offset by a 6.4% increase in the volume of KWHs purchased as the cost of available energy was lower than the Georgia Power-owned generation available.
For year-to-date 2012, purchased power expense from affiliates was $469 million compared to $513 million in the corresponding period in 2011. The decrease was due to a 24.9% decrease in the average cost per KWH purchased, reflecting lower natural gas prices, partially offset by a 10.4% increase in the volume of KWHs purchased as the cost of the available energy was lower than the Georgia Power-owned generation available.
Energy purchases from affiliates will vary depending on the 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 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(55)
 
(12.1)
 
$(51)
 
(3.9)
In the third quarter 2012, other operations and maintenance expenses were $398 million compared to $453 million in the corresponding period in 2011. For year-to-date 2012, other operations and maintenance expenses were $1.24 billion compared to $1.29 billion in the corresponding period in 2011. The decreases in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 were primarily due to decreases in transmission and distribution maintenance and the timing of outages as the result of cost containment efforts to offset the effect of milder weather in 2012, and decreases in uncollectible account expense of $6 million and $15 million, respectively, partially offset by increases in employee benefits expense of $10 million and $30 million, respectively.
Depreciation and Amortization
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$6
 
3.3
 
$28
 
5.3
In the third quarter 2012, depreciation and amortization was $186 million compared to $180 million in the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $559 million compared to $531 million in the corresponding period in 2011. The increases were primarily due to increases of $15 million and $42 million, respectively, in depreciation on additional plant in service primarily related to new generation at Plant McDonough-Atkinson Units 4 and 5, partially offset by $9 million and $18 million, respectively, in amortization of the regulatory liability for state income tax credits as authorized by the Georgia PSC. See Note 3 to the financial statements of Georgia Power under "Income Tax Matters – Georgia State Income Tax Credits" in Item 8 of the Form 10-K.

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


Allowance for Equity Funds Used During Construction
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(11)
 
(42.3)
 
$(32)
 
(43.8)
In the third quarter 2012, AFUDC equity was $15 million compared to $26 million in the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $41 million compared to $73 million in the corresponding period in 2011. The decreases were primarily due to the completion of Plant McDonough-Atkinson Units 4 and 5 in December 2011 and April 2012, respectively.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$5
 
5.6
 
$19
 
7.4
In the third quarter 2012, interest expense, net of amounts capitalized was $95 million compared to $90 million in the corresponding period in 2011. The increase was immaterial. For year-to-date 2012, interest expense, net of amounts capitalized was $276 million compared to $257 million in the corresponding period in 2011. The increase was primarily due to a $23 million reduction in interest expense in 2011 resulting from the settlement of litigation with the Georgia Department of Revenue, as well as a $10 million decrease in allowance for debt funds used during construction due to the completion of Plant McDonough-Atkinson Units 4 and 5 discussed above. See Note 3 to the financial statements of Georgia Power under "Income Tax Matters – Georgia State Income Tax Credits" in Item 8 of the Form 10-K for additional information on the litigation settlement.
Income Taxes
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$11
 
3.6
 
$(25)
 
(4.3)
In the third quarter 2012, income taxes were $314 million compared to $303 million in the corresponding period in 2011. The increase was primarily due to higher pre-tax earnings and a decrease in non-taxable AFUDC equity.
For year-to-date 2012, income taxes were $558 million compared to $583 million in the corresponding period in 2011. The decrease was primarily due to lower pre-tax earnings and state income tax credits, partially offset by a decrease in non-taxable AFUDC equity.
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 selling electricity. 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. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced 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. Changes in economic conditions impact sales for Georgia Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

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


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. 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.
New Source Review Actions
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Environmental Matters – New Source Review Actions" herein for additional information. The case against Georgia Power was administratively closed in 2001 and has not been reopened. The ultimate outcome of this matter cannot be determined at this time.
Climate Change Litigation
Kivalina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. On October 8, 2012, the plaintiffs filed for review of the decision by the U.S. Court of Appeals for the Ninth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Hurricane Katrina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" of Georgia Power in Item 7 of the Form 10-K for information regarding Georgia Power's estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Georgia Power's preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA's final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA's proposed water and coal combustion byproducts rules.

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


Georgia Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA's proposed water and coal combustion byproducts rules. As part of the development of its compliance strategy for the MATS rule, Georgia Power has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from certain generating units. While the final MATS compliance plan is still being developed and the ultimate costs remain uncertain, compliance decisions made in 2012 have allowed Georgia Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period (in addition to $237 million included in base environmental capital disclosed in the Form 10-K) have been revised from up to $320 million to approximately $440 million as follows:
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
MATS rule
 
$
—

 
$
—

 
$
440

In addition, Georgia Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $640 million to approximately $250 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:
 
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
Proposed water and coal combustion byproducts rules
 
$
5

 
$
55

 
$
190

While Georgia Power's ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Georgia Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $5 billion to $7 billion range provided in the Form 10-K.
Georgia Power's ultimate compliance strategy and actual future environmental capital expenditures are dependent on development of the final MATS compliance plan and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Georgia Power's fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time.
As part of SEGCO's environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Georgia Power and Alabama Power. The capacity of SEGCO's units is sold to Georgia Power and Alabama Power through a PPA. See Note 4 to the financial statements of Georgia Power in Item 8 of the Form 10-K for additional information. The impact of SEGCO's ultimate compliance strategy on the PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Georgia Power's financial statements.

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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 on the eight-hour ozone and fine particulate matter air quality standards, the MATS rule, the Cross-State Air Pollution Rule (CSAPR), and the Clean Air Visibility Rule (CAVR).
On May 21, 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. The only area within Georgia Power's service territory designated as a nonattainment area was a 15-county area within metropolitan Atlanta. The potential impact of the revised standard and nonattainment designation will depend on further evaluation and implementation by the Georgia Environmental Protection Division and cannot be determined at this time.
On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Georgia Power's service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Georgia Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
On August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety and directed the EPA to continue to administer the Clean Air Interstate Rule pending the EPA's development of a valid replacement. The vacatur of CSAPR creates additional uncertainty with respect to whether additional controls may be required for CAVR and best available retrofit technology compliance. On October 5, 2012, the EPA filed for review of the decision by the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter depends on the outcome of any legal challenges and further action by the EPA and cannot be determined at this time.
On August 29, 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized, the revisions would apply the NSPS to all new, reconstructed, and modified CTs, including CTs at combined cycle units, during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and 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 on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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Coal Combustion Byproducts
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Georgia Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. 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 April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA's actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
PSC Matters
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate Plans" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K for additional information on Georgia Power's 2010 ARP.
In accordance with the terms of the 2010 ARP, on November 1, 2012, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective on January 1, 2013:
•
Increase the DSM tariffs by approximately $16 million;
•
Increase the traditional base tariffs by approximately $58 million to recover the revenue requirements for Plant McDonough-Atkinson Units 4, 5, and 6 for the period through December 31, 2013, which also reflects a separate settlement agreement associated with the June 30, 2011 quarterly construction monitoring report for Plant McDonough-Atkinson (see Note 3 to the financial statements of Georgia Power under "Construction – Other Construction" in Item 8 of the Form 10-K for additional information); and
•
Increase the MFF tariff, consistent with the adjustments above, as well as those related to the IFR and NCCR tariff adjustments described under "Fuel Cost Recovery" and "Construction – Nuclear," respectively, herein.

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Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
On June 21, 2012, the Georgia PSC approved a 19% decrease in Georgia Power's fuel cost recovery rates, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.
As of September 30, 2012, Georgia Power's fuel cost over recovery balance totaled $199 million. This balance is slightly below the $200 million required to automatically trigger the Georgia PSC's approved IFR adjustment mechanism. On November 1, 2012, Georgia Power filed a request with the Georgia PSC to reduce fuel cost recovery rates effective January 1, 2013 using the IFR process. The requested reduction would reduce annual billings by approximately $122 million. In accordance with the IFR process, the Georgia PSC will have 30 days to consider Georgia Power's request. The ultimate outcome of this matter cannot be determined at this time.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Power's revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information.
2011 Integrated Resource Plan Update
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality," " – Water Quality," and " – Coal Combustion Byproducts" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" and " – 2011 Integrated Resource Plan Update" in Item 8 of the Form 10-K for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia's Multi-Pollutant Rule; Georgia Power's analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; the 2010 ARP; and the 2011 IRP Update.
On March 20, 2012, the Georgia PSC approved Georgia Power's request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Power's 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.
Separately, on October 16, 2012, the Georgia PSC approved a 50 MW PPA with a Qualifying Facility for capacity and energy that will commence in 2015 and end in 2035.
Advanced Solar Initiative
Georgia Power filed a new solar initiative with the Georgia PSC on September 26, 2012. If approved, Georgia Power may acquire up to 210 MWs of additional solar capacity over a three-year period through long-term contracts. The ultimate outcome of this matter cannot be determined at this time.

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Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Georgia Power through 2013. Consequently, Georgia Power's positive cash flow benefit is estimated to be between $410 million and $460 million in 2012.
Construction
Nuclear
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction – Nuclear" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Construction – Nuclear" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4.
On February 16, 2012, a group of petitioners who had intervened in the NRC's combined construction and operating licenses (COLs) proceedings for Plant Vogtle Units 3 and 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the NRC's issuance of the COLs. In addition, on February 16, 2012, another group of petitioners filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC's certification of the Westinghouse Design Control Document, as amended (DCD). On April 3, 2012, the U.S. Court of Appeals for the District of Columbia Circuit granted a motion filed by these two groups of petitioners to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the COLs for Plant Vogtle Units 3 and 4 with the U.S. District Court for the District of Columbia. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners' motion to stay the effectiveness of the COLs. Georgia Power has intervened in and intends to vigorously contest these petitions.
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related CWIP accounts in rate base. Also in 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related CWIP accounts in rate base during the construction period. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. On August 21, 2012, the Georgia PSC voted to approve Georgia Power's sixth semi-annual construction monitoring report including total costs of $2.0 billion for Plant Vogtle Units 3 and 4 incurred through December 31, 2011. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.
In addition, in December 2010, the Georgia PSC approved Georgia Power's NCCR tariff. The NCCR tariff became effective January 1, 2011 and adjustments are filed with the Georgia PSC on November 1 of each year to become effective on January 1 of the following year. On November 1, 2012, Georgia Power filed to increase the NCCR tariff by approximately $50 million effective January 1, 2013. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2012, approximately $59 million of these 2009 and 2010 costs remained in CWIP.

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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 (collectively, Owners) and Westinghouse and Stone & Webster, Inc. (collectively, Contractor) have established both informal and formal dispute resolution procedures in accordance with the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement) in order to resolve issues arising during the course of constructing a project of this magnitude. The Contractor and Georgia Power (on behalf of the Owners) have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to costs associated with design changes to the DCD and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the COLs by the NRC. The Owners and the Contractor have begun negotiations regarding these issues, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Through correspondence sent to the Owners, the Contractor provided its proposed adjustment to the contract price and initiated the formal dispute resolution process. The Contractor's estimated adjustment attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars) with respect to these issues. Georgia Power has not agreed with the amount of these proposed adjustments or that the Owners have responsibility for any costs related to these issues. On November 1, 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Owners are not responsible for the costs related to these issues. Also on November 1, 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia, alleging the Owners are responsible for the costs related to these issues and seeking payment from the Owners of the full amount of these costs. While litigation has commenced, Georgia Power expects negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Georgia Power intends to vigorously defend its positions. If these costs ultimately are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. In connection with these negotiations, the Owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are expected to arise throughout the construction of Plant Vogtle Units 3 and 4.
In addition, there are processes in place that are designed to assure compliance with the design requirements specified in the DCD and the COLs, including rigorous inspection by Southern Nuclear and the NRC that occurs throughout construction. During a routine inspection in April 2012, the NRC identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the NRC. The design changes were determined to have minimal safety significance and, on October 18, 2012, the NRC approved a license amendment request to clarify that the nuclear island concrete and rebar construction will conform to NRC requirements. Various inspection and other issues are expected to arise from time to time as construction proceeds, which may result in additional license amendments or require other resolution.
There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including legal challenges to the NRC issuance of the COLs and certification of the DCD. Similar additional challenges at the state and federal level are expected as construction proceeds.
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.

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The ultimate outcome of these matters cannot be determined at this time.
Other Construction
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction – Other Construction" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Construction – Other Construction" in Item 8 of the Form 10-K for additional information.
Plant McDonough Unit 1 was retired on February 29, 2012. Georgia Power placed Plant McDonough-Atkinson Unit 5 into service on April 26, 2012 and Plant McDonough-Atkinson Unit 6 into service on October 28, 2012.
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 increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, 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 the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, including the one in use at Plant Hatch, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. On August 29, 2012, the NRC staff issued the final interim staff guidance document, which offers acceptable approaches to meeting the requirements of the NRC's orders before the December 31, 2016 compliance deadline. The interim staff guidance is not mandatory, but licensees would be required to obtain NRC approval for taking an approach other than as outlined in the interim staff guidance. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the NRC and 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. The ultimate outcome of these events cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in 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

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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 Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
In March 2012, Georgia Power began using automated meter readings to measure unbilled KWH sales for energy delivered through month end. As of September 30, 2012, these measured unbilled KWH sales represent approximately 90% of total unbilled KWH sales. Increased usage of actual data to compute unbilled revenues reduces the impact that estimates could have on Georgia Power's results of operations; therefore, Georgia Power no longer considers unbilled revenue a critical accounting estimate.
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, 2012. Georgia 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 "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
Net cash provided from operating activities totaled $1.97 billion for the first nine months of 2012 compared to $2.08 billion for the corresponding period in 2011. The decrease was primarily due to lower retail operating revenues, higher fuel inventory additions in 2012, and lower deferred taxes due to the effect of bonus depreciation in 2011, partially offset by higher recovery of retail fuel costs. Net cash used for investing activities totaled $1.47 billion primarily related to the construction of Plant Vogtle Units 3 and 4 and Plant McDonough-Atkinson Units 5 and 6. Net cash used for financing activities totaled $92 million for the first nine months of 2012 compared to $732 million used for financing activities in the corresponding period in 2011. The decrease is primarily due to increased debt issuances in 2012 to support the ongoing construction program. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2012 include increases of $701 million in total property, plant, and equipment, $590 million in debt, and $412 million in cash and cash equivalents, as well as a $336 million change in under/over recovered fuel.
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 to comply with existing environmental regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $1.46 billion will be required through September 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL – "Environmental Statutes and Regulations – General" herein for a description of Georgia Power's estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.

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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 units, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia 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.
On March 20, 2012, the Georgia PSC approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. However, these PPAs remain subject to FERC approval. See FUTURE EARNINGS POTENTIAL – "PSC Matters – 2011 Integrated Resource Plan Update" herein for additional information. On October 16, 2012, the Georgia PSC approved a 50 MW PPA with a Qualifying Facility for capacity and energy that will commence in 2015 and end in 2035. These four PPAs will be accounted for as operating leases and are expected to result in additional obligations of approximately $69 million in 2015, $82 million in 2016, and a total of $1.35 billion thereafter. The ultimate outcome of this matter cannot be determined at this time.
Sources of Capital
Except as described below with respect to potential DOE loan guarantees, 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, 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 Georgia Power in Item 7 of the Form 10-K for additional information.
In June 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future borrowings by Georgia Power related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs, or approximately $3.46 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. See FUTURE EARNINGS POTENTIAL – "Construction – Nuclear" herein for more information on Plant Vogtle Units 3 and 4.
Georgia 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 cash needs, which can fluctuate significantly due to the seasonality of the business.

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At September 30, 2012, Georgia Power had approximately $425 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2012, including expiration dates, were as follows:
Expires
 
 
 
Executable Term Loans
 
Due Within One Year(a)
2012
 
2013
 
2014 and
Beyond

 
Total
 
Unused
 
One Year
 
Two Years
 
Term Out
 
No Term
Out

(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
$
—

 
$
—

 
$
1,750

 
$
1,750

 
$
1,740

 
$
—

 
$
—

 
$
—

 
$
—

 (a) Reflects facilities expiring on or before September 30, 2013.
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.
Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Georgia Power. Georgia Power is currently in compliance with all such covenants. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Georgia Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2012 was approximately $868 million.
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 operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
During the three months ended September 30, 2012, Georgia Power had no commercial paper or other short-term debt outstanding.
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Georgia 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 Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. The maximum potential collateral requirements under these contracts at September 30, 2012 were as follows:
 
 
 
Credit Ratings
Maximum Potential
Collateral Requirements
 
(in millions)
At BBB- and/or Baa3
$
65

Below BBB- and/or Baa3
1,296


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


Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant 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, any credit rating downgrade could impact Georgia Power's ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Georgia Power's market risk exposure relative to interest rate changes for the third quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power had no material change in market risk exposure for the third quarter 2012 relative to fuel and electricity prices when compared with the December 31, 2011 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and nine months ended September 30, 2012 were as follows: 
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(58
)
 
$
(82
)
Contracts realized or settled
 
18

 
63

Current period changes(a)
 
13

 
(8
)
Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(27
)
 
$
(27
)
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and nine months ended September 30, 2012 were as follows: 
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
16

 
$
42

Natural gas options
 
15

 
13

Total changes
 
$
31

 
$
55


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


The net hedge volumes of energy-related derivative contracts were as follows: 
 
 
September 30,
2012
 
June 30,
2012
 
December 31,
2011
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
17

 
23

 
29

Commodity – Natural gas options
 
90

 
73

 
44

Total hedge volume
 
107

 
96

 
73

The weighted average swap contract cost above market prices was approximately $0.88 per mmBtu as of September 30, 2012, $1.37 per mmBtu as of June 30, 2012, and $1.65 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All natural gas hedge gains and losses are recovered through Georgia Power's fuel cost recovery mechanism.
Regulatory hedges relate to Georgia Power's fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Georgia Power's fuel cost recovery mechanism.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.
Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2012 were as follows: 
 
 
September 30, 2012
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3  
 
 
 
 
(in millions)
 
 
Level 1
 
$
—

 
$
—

 
$
—

Level 2
 
(27
)
 
(22
)
 
(5
)
Level 3
 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(27
)
 
$
(22
)
 
$
(5
)
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Georgia Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Georgia Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Georgia Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Georgia Power in Item 7 and Note 1 under "Financial Instruments" and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

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


Financing Activities
In January 2012, Georgia Power entered into a six-month floating rate bank loan in an aggregate amount of $100 million, bearing interest based on one-month LIBOR. The proceeds were used for general corporate purposes, including Georgia Power's continuous construction program. This bank loan was paid at maturity on July 10, 2012.
In March 2012 and May 2012, Georgia Power issued $750 million and $350 million, respectively, aggregate principal amount of Series 2012A 4.30% Senior Notes due March 15, 2042. Also in May 2012, Georgia Power issued $400 million aggregate principal amount of Series 2012B 2.85% Senior Notes due May 15, 2022. The net proceeds from the sale of the Series 2012B Senior Notes, together with the net proceeds from the sale of the Series 2012A Senior Notes, were used to repay a portion of Georgia Power's short-term debt and bank loans, for the redemption in July 2012 of $300 million aggregate principal amount of Georgia Power's Series 2007D 6.375% Senior Notes due July 15, 2047, and for general corporate purposes, including Georgia Power's continuous construction program.
In May 2012, the Development Authority of Monroe County issued $48.72 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2012 for the benefit of Georgia Power. The proceeds were used in June 2012 to redeem $48.72 million aggregate principal amount of Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2006.
In June 2012, the Development Authority of Burke County issued $85 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2012 and $100 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2012 for the benefit of Georgia Power. The proceeds were used in July 2012 to redeem $85 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2005 and $100 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2005.
In August 2012, Georgia Power issued $400 million aggregate principal amount of Series 2012C 0.75% Senior Notes due August 10, 2015. The proceeds were used in September 2012 to redeem $250 million aggregate principal amount of Georgia Power's Series 2007E 6.00% Senior Insured Monthly Notes due September 1, 2040 and for general corporate purposes, including Georgia Power's continuous construction program.
Subsequent to September 30, 2012, Georgia Power announced the redemption that will occur in December 2012 of $100 million aggregate principal amount of its Series 2007F 6.05% Senior Monthly Notes due December 1, 2038.
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

87
Table of Contents


GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
(in thousands)
Operating Revenues:
 
 
 
 
 
 
 
Retail revenues
$
347,435

 
$
362,109

 
$
880,833

 
$
957,409

Wholesale revenues, non-affiliates
27,462

 
33,921

 
83,309

 
103,814

Wholesale revenues, affiliates
30,113

 
52,833

 
95,179

 
79,825

Other revenues
16,809

 
19,167

 
48,951

 
50,855

Total operating revenues
421,819

 
468,030

 
1,108,272

 
1,191,903

Operating Expenses:
 
 
 
 
 
 
 
Fuel
160,749

 
220,305

 
423,057

 
530,773

Purchased power, non-affiliates
18,380

 
20,046

 
41,690

 
37,938

Purchased power, affiliates
10,785

 
9,941

 
18,508

 
39,108

Other operations and maintenance
74,781

 
74,144

 
229,790

 
227,236

Depreciation and amortization
36,169

 
32,673

 
104,649

 
96,733

Taxes other than income taxes
27,142

 
29,467

 
76,202

 
79,230

Total operating expenses
328,006

 
386,576

 
893,896

 
1,011,018

Operating Income
93,813

 
81,454

 
214,376

 
180,885

Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
1,015

 
2,434

 
3,988

 
7,091

Interest income
10

 
22

 
1,406

 
56

Interest expense, net of amounts capitalized
(14,637
)
 
(15,156
)
 
(45,703
)
 
(43,208
)
Other income (expense), net
(567
)
 
(451
)
 
(1,860
)
 
(1,461
)
Total other income and (expense)
(14,179
)
 
(13,151
)
 
(42,169
)
 
(37,522
)
Earnings Before Income Taxes
79,634

 
68,303

 
172,207

 
143,363

Income taxes
30,329

 
25,535

 
64,172

 
52,451

Net Income
49,305

 
42,768

 
108,035

 
90,912

Dividends on Preference Stock
1,551

 
1,551

 
4,652

 
4,652

Net Income After Dividends on Preference Stock
$
47,754

 
$
41,217

 
$
103,383

 
$
86,260

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
(in thousands)
Net Income After Dividends on Preference Stock
$
47,754

 
$
41,217

 
$
103,383

 
$
86,260

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Reclassification adjustment for amounts included in net income, net of tax of $90, $90, $270 and $270, respectively
143

 
143

 
429

 
430

Total other comprehensive income (loss)
143

 
143

 
429

 
430

Comprehensive Income
$
47,897

 
$
41,360

 
$
103,812

 
$
86,690

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

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GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
(in thousands)
Operating Activities:
 
 
 
Net income
$
108,035

 
$
90,912

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
109,132

 
101,335

Deferred income taxes
132,367

 
56,869

Allowance for equity funds used during construction
(3,988
)
 
(7,091
)
Pension, postretirement, and other employee benefits
4,361

 
(179
)
Stock based compensation expense
1,346

 
1,055

Other, net
3,839

 
(5,787
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
(10,995
)
 
(13,605
)
-Prepayments
3,066

 
7,745

-Fossil fuel stock
14,055

 
36,802

-Materials and supplies
(3,859
)
 
(6,382
)
-Prepaid income taxes
28,108

 
36,081

-Other current assets
—

 
(571
)
-Accounts payable
(453
)
 
(65
)
-Accrued taxes
18,566

 
22,186

-Accrued compensation
(4,263
)
 
(4,290
)
-Over recovered regulatory clause revenues
7,387

 
2,771

-Other current liabilities
(925
)
 
7,513

Net cash provided from operating activities
405,779

 
325,299

Investing Activities:
 
 
 
Property additions
(239,705
)
 
(228,696
)
Cost of removal, net of salvage
(20,931
)
 
(9,137
)
Change in construction payables
(542
)
 
636

Payments pursuant to long-term service agreements
(6,184
)
 
(6,173
)
Other investing activities
627

 
303

Net cash used for investing activities
(266,735
)
 
(243,067
)
Financing Activities:
 
 
 
Decrease in notes payable, net
(91,699
)
 
(56,607
)
Proceeds —
 
 
 
Common stock issued to parent
40,000

 
50,000

Capital contributions from parent company
1,569

 
1,569

Senior notes
100,000

 
125,000

Redemptions —
 
 
 
Senior notes
(91,363
)
 
(553
)
Other long-term debt
—

 
(110,000
)
Payment of preference stock dividends
(4,652
)
 
(4,652
)
Payment of common stock dividends
(86,850
)
 
(82,500
)
Other financing activities
(468
)
 
(3,593
)
Net cash provided from (used for) financing activities
(133,463
)
 
(81,336
)
Net Change in Cash and Cash Equivalents
5,581

 
896

Cash and Cash Equivalents at Beginning of Period
17,328

 
16,434

Cash and Cash Equivalents at End of Period
$
22,909

 
$
17,330

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $1,846 and $2,826 capitalized for 2012 and 2011, respectively)
$
38,806

 
$
36,427

Income taxes, net
(101,825
)
 
(46,319
)
Noncash transactions — accrued property additions at end of period
25,115

 
15,820

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

89
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GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30,
2012
 
At December 31,
2011
 
 
(in thousands)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
22,909

 
$
17,328

Receivables —
 
 
 
 
Customer accounts receivable
 
87,198

 
72,754

Unbilled revenues
 
52,812

 
49,921

Under recovered regulatory clause revenues
 
6,757

 
5,530

Other accounts and notes receivable
 
10,626

 
13,350

Affiliated companies
 
8,359

 
14,844

Accumulated provision for uncollectible accounts
 
(1,745
)
 
(1,962
)
Fossil fuel stock, at average cost
 
133,512

 
147,567

Materials and supplies, at average cost
 
54,189

 
49,781

Other regulatory assets, current
 
27,247

 
35,849

Prepaid expenses
 
43,845

 
28,327

Other current assets
 
5,185

 
2,051

Total current assets
 
450,894

 
435,340

Property, Plant, and Equipment:
 
 
 
 
In service
 
4,126,794

 
3,846,446

Less accumulated provision for depreciation
 
1,149,685

 
1,124,291

Plant in service, net of depreciation
 
2,977,109

 
2,722,155

Construction work in progress
 
201,929

 
287,173

Total property, plant, and equipment
 
3,179,038

 
3,009,328

Other Property and Investments
 
15,765

 
16,394

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
51,939

 
48,210

Other regulatory assets, deferred
 
333,299

 
323,116

Other deferred charges and assets
 
36,611

 
39,493

Total deferred charges and other assets
 
421,849

 
410,819

Total Assets
 
$
4,067,546

 
$
3,871,881

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


90
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GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity
 
At September 30,
2012
 
At December 31,
2011
 
 
(in thousands)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
60,000

 
$
—

Notes payable
 
19,228

 
114,507

Accounts payable —
 
 
 
 
Affiliated
 
72,051

 
54,874

Other
 
51,500

 
63,265

Customer deposits
 
35,805

 
35,779

Accrued taxes —
 
 
 
 
Accrued income taxes
 
5,438

 
1,362

Other accrued taxes
 
25,888

 
12,114

Accrued interest
 
17,622

 
14,018

Accrued compensation
 
10,222

 
14,485

Other regulatory liabilities, current
 
51,585

 
35,639

Liabilities from risk management activities
 
12,851

 
22,786

Other current liabilities
 
20,353

 
22,916

Total current liabilities
 
382,543

 
391,745

Long-term Debt
 
1,185,719

 
1,235,447

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
616,122

 
458,978

Accumulated deferred investment tax credits
 
5,746

 
6,760

Employee benefit obligations
 
109,721

 
109,740

Other cost of removal obligations
 
215,138

 
214,598

Other regulatory liabilities, deferred
 
53,796

 
44,843

Other deferred credits and liabilities
 
214,687

 
186,824

Total deferred credits and other liabilities
 
1,215,210

 
1,021,743

Total Liabilities
 
2,783,472

 
2,648,935

Preference Stock
 
97,998

 
97,998

Common Stockholder's Equity:
 
 
 
 
Common stock, without par value—
 
 
 
 
Authorized — 20,000,000 shares
 
 
 
 
Outstanding — September 30, 2012: 4,542,717 shares
 
 
 
 
                — December 31, 2011: 4,142,717 shares
 
393,060

 
353,060

Paid-in capital
 
546,875

 
542,709

Retained earnings
 
247,866

 
231,333

Accumulated other comprehensive loss
 
(1,725
)
 
(2,154
)
Total common stockholder's equity
 
1,186,076

 
1,124,948

Total Liabilities and Stockholder's Equity
 
$
4,067,546

 
$
3,871,881

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

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

THIRD QUARTER 2012 vs. THIRD QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricity 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 selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel prices, and storm restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSC's decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Power's authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Power's retail base rates and charges of $4 million to be effective in January 2013.
Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Gulf Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$6.5
 
15.9
 
$17.1
 
19.9
Gulf Power's net income after dividends on preference stock for the third quarter 2012 was $47.7 million compared to $41.2 million for the corresponding period in 2011. The increase was primarily due to higher revenues due to increases in retail base rates, partially offset by milder weather in 2012 and a decrease in retail energy sales in 2012 due to a decrease in customer usage.
Gulf Power's net income after dividends on preference stock for year-to-date 2012 was $103.4 million compared to $86.3 million for the corresponding period in 2011. The increase was primarily due to higher revenues due to increases in retail base rates and higher wholesale capacity revenues from non-affiliates in 2012. These increases were partially offset by milder weather in 2012 and a decrease in retail energy sales in 2012 due to a decrease in customer usage.

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

Retail Revenues
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(14.7)
 
(4.1)
 
$(76.6)
 
(8.0)
In the third quarter 2012, retail revenues were $347.4 million compared to $362.1 million for the corresponding period in 2011. For year-to-date 2012, retail revenues were $880.8 million compared to $957.4 million for the corresponding period in 2011.
Details of the change to retail revenues were as follows:
 
 
Third Quarter
2012
 
Year-to-Date
2012
 
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail – prior year
 
$
362.1

 
 
 
$
957.4

 
 
Estimated change in –
 
 
 
 
 
 
 
 
Rates and pricing
 
17.7

 
4.9

 
49.9

 
5.2

Sales growth (decline)
 
(0.4
)
 
(0.2
)
 
(5.5
)
 
(0.6
)
Weather
 
(1.8
)
 
(0.5
)
 
(10.5
)
 
(1.1
)
Fuel and other cost recovery
 
(30.2
)
 
(8.3
)
 
(110.5
)
 
(11.5
)
Retail – current year
 
$
347.4

 
(4.1
)%
 
$
880.8

 
(8.0
)%
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC 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 2012 when compared to the corresponding periods in 2011 primarily due to higher revenues due to increases in retail base rates and revenues associated with higher recoverable costs under Gulf Power's energy conservation cost recovery clause, partially offset by a decrease in revenues associated with lower recoverable costs under Gulf Power's environmental cost recovery clause.
Revenues attributable to changes in sales decreased in the third quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted KWH energy sales to residential and commercial customers decreased 2.1% and 0.3%, respectively, primarily due to lower use per customer. KWH energy sales to industrial customers decreased 4.2% primarily due to a billing adjustment recorded in July 2011, partially offset by an increase in sales due to decreased customer co-generation and changes in customer production levels.
Revenues attributable to changes in sales decreased year-to-date 2012 when compared to the corresponding period in 2011. Weather-adjusted KWH energy sales to residential and commercial customers decreased 1.9% and 1.3%, respectively, due to lower use per customer. KWH energy sales to industrial customers decreased 6.6% primarily due to increased customer co-generation due to the lower cost of natural gas in 2012 and changes in customer production levels.
Revenues attributable to changes in weather decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to milder weather in 2012.

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Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to lower costs due to lower natural gas prices and decreased KWH energy sales. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" herein for additional information.
Wholesale Revenues – Non-Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(6.5)
 
(19.0)
 
$(20.5)
 
(19.8)
Wholesale 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 service territory, and the availability of the Southern Company system's generation. Wholesale revenues from non-affiliates include unit power sales under long-term contracts to other utilities in Florida and Georgia. Wholesale revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost.
In the third quarter 2012, wholesale revenues from non-affiliates were $27.4 million compared to $33.9 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 43.1% decrease in KWH sales as a result of less energy scheduled by unit power customers due to their use of lower cost generation resources to serve their loads. The decrease was partially offset by an 8.0% increase in capacity revenues related to higher capacity rates resulting from change-in-law contract provisions that provide for recovery of costs related to the generating resource's compliance with new environmental requirements.
For year-to-date 2012, wholesale revenues from non-affiliates were $83.3 million compared to $103.8 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 51.3% decrease in KWH sales as a result of less energy scheduled by unit power customers due to their use of lower cost generation resources to serve their loads. The decrease was partially offset by a 12.4% increase in capacity revenues related to higher capacity rates resulting from change-in-law contract provisions that provide for recovery of costs related to the generating resource's compliance with new environmental requirements.
Wholesale Revenues – Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(22.7)
 
(43.0)
 
$15.4
 
19.2
Wholesale revenues from sales to affiliated companies within the Southern Company system 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 fuel revenue related to energy sales and the cost of energy purchases are both included in the determination of recoverable fuel costs and are generally offset by revenues collected in Gulf Power's fuel cost recovery clause.
In the third quarter 2012, wholesale revenues from affiliates were $30.1 million compared to $52.8 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 19.7% decrease in KWH sales to serve affiliate demand, primarily resulting from milder weather in the third quarter 2012 compared to the corresponding period in 2011, and a 29.0% decrease in the price of energy in the third quarter 2012.

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For year-to-date 2012, wholesale revenues from affiliates were $95.2 million compared to $79.8 million for the corresponding period in 2011. The increase was primarily due to higher energy revenues related to a 99.1% increase in KWH sales resulting from the availability of Gulf Power's lower priced generation resources to serve affiliate demand. The increase was partially offset by a 40.1% decrease in the price of energy for year-to-date 2012.
Fuel and Purchased Power Expenses
 
 
Third Quarter 2012
vs.
Third Quarter 2011
 
Year-to-Date 2012
vs.
Year-to-Date 2011
 
 
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
Fuel
 
$
(59.5
)
 
(27.0
)
 
$
(107.7
)
 
(20.3
)
Purchased power – non-affiliates
 
(1.7
)
 
(8.3
)
 
3.8

 
9.9

Purchased power – affiliates
 
0.8

 
8.5

 
(20.6
)
 
(52.7
)
Total fuel and purchased power expenses
 
$
(60.4
)
 
 
 
$
(124.5
)
 
 
In the third quarter 2012, total fuel and purchased power expenses were $189.9 million compared to $250.3 million for the corresponding period in 2011. The decrease in fuel and purchased power expenses was primarily due to a $29.3 million decrease in the average cost of fuel and purchased power and a $43.5 million decrease related to the volume of KWHs generated. The decrease was partially offset by a $12.4 million increase related to the volume of KWHs purchased.
For year-to-date 2012, total fuel and purchased power expenses were $483.3 million compared to $607.8 million for the corresponding period in 2011. The decrease in fuel and purchased power expenses was primarily due to a $136.0 million decrease in the average cost of fuel and purchased power and a $96.7 million decrease related to the volume of KWHs generated. The decrease was partially offset by a $108.2 million increase related to the volume of KWHs purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel cost and purchased power capacity recovery clauses. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" and "– Purchased Power Capacity Recovery" herein for additional information.
Details of Gulf Power's generation and purchased power were as follows: 
 
 
Third Quarter
2012
 
Third Quarter
2011
 
Year-to-Date
2012
 
Year-to-Date
2011
Total generation (millions of KWHs)
 
2,642

 
3,531

 
7,633

 
9,562

Total purchased power (millions of KWHs)
 
1,992

 
1,729

 
5,352

 
3,124

Sources of generation (percent) –
 
 
 
 
 
 
 
 
Coal
 
63

 
70

 
61

 
70

Gas
 
37

 
30

 
39

 
30

Cost of fuel, generated (cents per net KWH) –
 
 
 
 
 
 
 
 
Coal
 
4.56

 
4.94

 
4.41

 
4.99

Gas
 
4.39

 
4.42

 
4.00

 
4.27

Average cost of fuel, generated (cents per net KWH)
 
4.50

 
4.79

 
4.25

 
4.77

Average cost of purchased power (cents per net KWH)(a)
 
3.57

 
4.70

 
2.97

 
4.86

(a) Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.

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Fuel
In the third quarter 2012, fuel expense was $160.8 million compared to $220.3 million for the corresponding period in 2011. The decrease was primarily due to a higher utilization of lower cost natural gas-fired sources, a 0.7% decrease in the average cost of natural gas per KWH generated, and a 25.2% decrease in KWHs generated as a result of displacement of coal-fired generation by energy purchases and lower demand related to milder weather in 2012. These decreases were partially offset by a 15.2% increase in KWHs purchased.
For year-to-date 2012, fuel expense was $423.1 million compared to $530.8 million for the corresponding period in 2011. The decrease was primarily due to a higher utilization of lower cost natural gas-fired sources, a 6.3% decrease in the average cost of natural gas per KWH generated, and a 20.2% decrease in KWHs generated as a result of displacement of coal-fired generation by energy purchases and lower demand related to milder weather and decreased customer usage in 2012. These decreases were partially offset by a 71.3% increase in KWHs purchased.
In the third quarter and year-to-date 2012, the decrease in the average cost of fuel was a result of decreases in the average costs of natural gas and coal per KWH generated and a higher percentage of utilization of Gulf Power's lower cost natural gas-fired generation sources.
Purchased Power – Non-Affiliates
In the third quarter 2012, purchased power expense from non-affiliates was $18.3 million compared to $20.0 million for the corresponding period in 2011. The decrease was due to decreases of $1.5 million in energy costs and $0.2 million in capacity costs. The decrease in energy costs resulted from lower average cost per KWH purchased, partially offset by an increase in the volume of KWHs purchased.
For year-to-date 2012, purchased power expense from non-affiliates was $41.7 million compared to $37.9 million for the corresponding period in 2011. The increase was due to a $3.9 million increase in energy costs, partially offset by a $0.1 million decrease in capacity costs. The increase in energy costs was due to an increase in the volume of KWHs purchased, partially offset by lower average cost per KWH.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2012, purchased power expense from affiliates was $10.8 million compared to $10.0 million for the corresponding period in 2011. The increase was due to increases of $0.6 million in energy costs and $0.2 million in capacity costs. The increase in energy costs was due to an increase in the volume of KWHs purchased, partially offset by a lower average cost per KWH purchased.
For year-to-date 2012, purchased power expense from affiliates was $18.5 million compared to $39.1 million for the corresponding period in 2011. The decrease was due to a decrease of $20.9 million in energy costs, partially offset by a $0.3 million increase in capacity costs. The decrease in energy costs was due to a decrease in the volume of KWHs purchased and a lower average cost per KWH purchased.
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.

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Other Operations and Maintenance Expenses
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$0.6
 
0.9
 
$2.6
 
1.1
In the third quarter 2012, other operations and maintenance expenses were $74.7 million compared to $74.1 million for the corresponding period in 2011. The increase was primarily due to a $3.6 million increase in routine and planned outage maintenance expense at generation facilities, partially offset by a $2.7 million decrease for labor and benefit-related expenses.
For year-to-date 2012, other operations and maintenance expenses were $229.8 million compared to $227.2 million for the corresponding period in 2011. The increase was primarily due to increases of $4.2 million for labor and benefit-related expenses and $5.2 million in marketing programs, partially offset by a $6.6 million decrease in routine and planned outage maintenance expense at generation facilities. The increased expense from marketing programs did not have a significant impact on earnings since the expense was offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Energy Conservation Cost Recovery" herein for additional information.
Depreciation and Amortization
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$3.5
 
10.7
 
$7.9
 
8.2
In the third quarter 2012, depreciation and amortization was $36.2 million compared to $32.7 million for the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $104.6 million compared to $96.7 million for the corresponding period in 2011. The increases were primarily due to additions of environmental control projects at generation facilities and net additions to transmission and distribution facilities.
Taxes Other Than Income Taxes
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(2.3)
 
(7.9)
 
$(3.0)
 
(3.8)
In the third quarter 2012, taxes other than income taxes were $27.1 million compared to $29.4 million for the corresponding period in 2011. The decrease was primarily due to a $2.5 million decrease in gross receipts taxes and franchise fees.
For year-to-date 2012, taxes other than income taxes were $76.2 million compared to $79.2 million for the corresponding period in 2011. The decrease was primarily due to a $4.6 million decrease in gross receipts taxes and franchise fees, partially offset by a $1.0 million increase in property taxes and a $0.6 million increase in payroll taxes. Gross receipts taxes and franchise fees have no impact on net income.
Allowance for Equity Funds Used During Construction
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(1.4)
 
(58.3)
 
$(3.1)
 
(43.8)
In the third quarter 2012, AFUDC equity was $1.0 million compared to $2.4 million for the corresponding period in 2011. The decrease was primarily due to the completion of construction projects related to environmental control projects at generating facilities.

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For year-to-date 2012, AFUDC equity was $4.0 million compared to $7.1 million for the corresponding period in 2011. The decrease was primarily due to an adjustment related to deferred future generation carrying costs and the completion of construction projects related to environmental control projects at generating facilities.
Interest Income
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$—
 
—
 
$1.4
 
N/M
N/M – Not meaningful
The amounts of interest income for the third quarter 2012 and the corresponding period in 2011 were immaterial.
Interest income was $1.4 million for year-to-date 2012 and was immaterial for the corresponding period in 2011. The year-to-date 2012 increase was primarily due to an IRS refund of interest claims for multiple tax years.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(0.5)
 
(3.4)
 
$2.5
 
5.8
In the third quarter 2012, interest expense, net of amounts capitalized was $14.7 million compared to $15.2 million for the corresponding period in 2011. The decrease was primarily due to lower interest rates on outstanding senior notes and customer deposits.
For year-to-date 2012, interest expense, net of amounts capitalized was $45.7 million compared to $43.2 million for the corresponding period in 2011. The increase was primarily due to net increases in long-term debt.
Income Taxes
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$4.8
 
18.8
 
$11.7
 
22.3
In the third quarter 2012, income taxes were $30.3 million compared to $25.5 million for the corresponding period in 2011. For year-to-date 2012, income taxes were $64.2 million compared to $52.5 million for the corresponding period in 2011. The increases were primarily due to higher pre-tax earnings.
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 selling electricity. 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. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced 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. Changes in economic conditions impact sales for Gulf Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

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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. 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 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.
New Source Review Actions
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Environmental Matters – New Source Review Actions" herein for additional information. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. The ultimate outcome of this matter cannot be determined at this time.
Climate Change Litigation
Kivalina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. On October 8, 2012, the plaintiffs filed for review of the decision by the U.S. Court of Appeals for the Ninth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Hurricane Katrina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" of Gulf Power in Item 7 of the Form 10-K for information regarding Gulf Power's estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Gulf Power's preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA's final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA's proposed water and coal combustion byproducts rules.

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Gulf Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA's proposed water and coal combustion byproducts rules. While the final MATS compliance plan is still being developed and the ultimate costs remain uncertain, compliance decisions made in 2012 have allowed Gulf Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $375 million to up to $205 million as follows: 
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
MATS rule
 
—
 
Up to $55
 
Up to $150
In addition, Gulf Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $105 million to up to $35 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows: 
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
Proposed water and coal combustion byproducts rules
 
—
 
Up to $10
 
Up to $25
While Gulf Power's ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Gulf Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) could be approximately $1.3 billion. Included in this amount is approximately $400 million that is also included in the 2012 through 2014 base level capital investment of Gulf Power described in the Form 10-K in anticipation of these rules.
Gulf Power's ultimate compliance strategy and actual future environmental capital expenditures are dependent on development of the final MATS compliance plan and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Gulf Power's fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Gulf Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards, the MATS rule, the Cross-State Air Pollution Rule (CSAPR), and the Clean Air Visibility Rule (CAVR).
On May 21, 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Gulf Power's service territory were designated as nonattainment areas.

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On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Gulf Power's service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Gulf Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.
On August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety and directed the EPA to continue to administer the Clean Air Interstate Rule pending the EPA's development of a valid replacement. The vacatur of CSAPR creates additional uncertainty with respect to whether additional controls may be required for CAVR and best available retrofit technology compliance. On October 5, 2012, the EPA filed for review of the decision by the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter depends on the outcome of any legal challenges and further action by the EPA and cannot be determined at this time.
On August 29, 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized, the revisions would apply the NSPS to all new, reconstructed, and modified CTs, including CTs at combined cycle units, during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and 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 Gulf Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Byproducts
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Gulf Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. The ultimate outcome of these matters cannot be determined at this time.

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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 April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA's actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
PSC Matters
Retail Base Rate Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Base Rate Case" of Gulf Power in Item 7 and 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 for additional information.
On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSC's decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Power's authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Power's retail base rates and charges of $4 million to be effective in January 2013.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC 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.
On November 5, 2012, the Florida PSC approved Gulf Power's annual rate clause requests for its fuel, purchased power capacity, conservation, and environmental compliance cost recovery factors for 2013. The net effect of the approved changes is a 1.9% rate increase for residential customers using 1,000 KWHs per month.
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
On June 19, 2012, the Florida PSC approved a decrease in Gulf Power's fuel rates of 7.8%, which will reduce annual billings by approximately $58.8 million effective July 2, 2012.

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

Over recovered fuel costs at September 30, 2012 totaled $28.5 million compared to $9.9 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein.
Purchased Power Capacity Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Purchased Power Capacity Recovery" of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Purchased Power Capacity Recovery," respectively, in Item 8 of the Form 10-K for additional information.
At September 30, 2012, the under recovered purchased power capacity costs totaled $3.3 million, which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein. At December 31, 2011, the over recovered purchased power capacity costs totaled $8.0 million, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein.
Environmental Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Cost Recovery" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
On April 3, 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015. Gulf Power's portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.
Over recovered environmental costs at September 30, 2012 totaled $6.9 million compared to $10.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein.
Energy Conservation Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Energy Conservation Cost Recovery" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.
Under recovered energy conservation costs at September 30, 2012 totaled $0.2 million compared to $3.1 million at December 31, 2011. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.

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

Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Gulf Power through 2013. Consequently, Gulf Power's positive cash flow benefit is estimated to be between $135 million and $150 million in 2012.
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 increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, 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 the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
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, 2012. Gulf 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 "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

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

Net cash provided from operating activities totaled $405.8 million for the first nine months of 2012 compared to $325.3 million for the corresponding period in 2011. The $80.5 million increase was primarily due to a $75.5 million increase in deferred income taxes primarily related to bonus depreciation. Net cash used for investing activities totaled $266.7 million in the first nine months of 2012 primarily due to property additions to utility plant and costs of removal. Net cash used for financing activities totaled $133.5 million for the first nine months of 2012. This was primarily due to short-term debt payments, long-term debt redemptions, and payment of common stock dividends, partially offset by common stock and long-term debt issuances. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2012 include a net increase of $169.7 million in property, plant, and equipment, primarily due to the addition of environmental control projects, an increase of $157.1 million in accumulated deferred income taxes, primarily related to bonus depreciation, an increase of $60.0 million in securities due within one year, an increase in common stock, without par value due to the issuance of common stock to Southern Company for $40 million, and a decrease of $95.3 million in notes payable primarily reduced by funds from operating activities and long-term debt.
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 with existing environmental regulations, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $60 million will be required through September 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL – "Environmental Statutes and Regulations – General" herein for a description of Gulf Power's estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
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 new regulatory requirements; 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 for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, 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 cash needs, which can fluctuate significantly due to the seasonality of the business.

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

At September 30, 2012, Gulf Power had approximately $22.9 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2012, including expiration dates, were as follows:
Expires
 
 
 
 
 
Executable Term
Loans
 
Due Within One
Year(a)
2012
 
2013
 
2014
 
Total
 
Unused
 
    One
    Year
 
Two    
Years    
 
    Term
    Out
 
No Term
Out
(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
$
20

 
$
60

 
$
195

 
$
275

 
$
275

 
$
45

 
—

 
$
45

 
$
35

 (a) Reflects facilities expiring on or before September 30, 2013.
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 arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Gulf Power. Gulf Power is currently in compliance with all such covenants. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Gulf Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2012 was approximately $69 million.
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 operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
Details of short-term borrowings were as follows: 
 
 
Short-term Debt at September 30, 2012
 
Short-term Debt During the Period(a)
 
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
 
(in millions)
 
 
 
(in millions)
 
 
 
(in millions)
Commercial paper
 
$
16

 
0.3
%
 
$
82

 
0.3
%
 
$
118

(a)
Average and maximum amounts are based upon daily balances during the three month period ended September 30, 2012.
Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

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

Credit Rating Risk
Gulf 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 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, 2012 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
 
(in millions)
At BBB- and/or Baa3
$
117

Below BBB- and/or Baa3
502

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant 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, any credit rating downgrade could impact Gulf Power's ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the third quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Gulf Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. Gulf Power continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the third quarter 2012 when compared with the December 31, 2011 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and nine months ended September 30, 2012 were as follows:
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(37
)
 
$
(41
)
Contracts realized or settled
 
8

 
27

Current period changes(a)
 
16

 
1

Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(13
)
 
$
(13
)
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and nine months ended September 30, 2012 were as follows: 
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
23

 
$
27

Natural gas options
 
1

 
1

Total changes
 
$
24

 
$
28

The net hedge volumes of energy-related derivative contracts were as follows: 
 
 
September 30,
2012
 
June 30,
2012
 
December 31,
2011
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
62

 
50

 
35

Commodity – Natural gas options
 
1

 
1

 
3

Total hedge volume
 
63

 
51

 
38

The weighted average swap contract cost above market prices was approximately $0.20 per mmBtu as of September 30, 2012, $0.72 per mmBtu as of June 30, 2012, and $1.14 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Natural gas settlements are recovered through Gulf Power's fuel cost recovery clause.
Regulatory hedges relate to Gulf Power's fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Gulf Power's fuel cost recovery clause.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.
Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2012 were as follows:
 
 
September 30, 2012    
Fair Value Measurements    
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(13
)
 
(9
)
 
(5
)
 
1

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(13
)
 
$
(9
)
 
$
(5
)
 
$
1


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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Gulf Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Gulf Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Gulf Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 and Note 1 under "Financial Instruments" and Note 10 to the financial statements of Gulf Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In January 2012, Gulf Power issued to Southern Company 400,000 shares of Gulf Power's common stock, without par value, and realized proceeds of $40 million. The proceeds were used to repay a portion of Gulf Power's short-term debt and for other general corporate purposes, including Gulf Power's continuous construction program.
In May 2012, Gulf Power issued $100 million aggregate principal amount of Series 2012A 3.10% Senior Notes due May 15, 2022. The proceeds from the sale of the Series 2012A Senior Notes were used by Gulf Power for the redemption in June 2012 of all of approximately $61 million aggregate principal amount of Gulf Power's Series F 5.60% Senior Insured Quarterly Notes due April 1, 2033 and $30 million aggregate principal amount of Gulf Power's Series H 5.25% Senior Notes due July 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Gulf Power's continuous construction program.
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,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
(in thousands)
Operating Revenues:
 
 
 
 
 
 
 
Retail revenues
$
220,296

 
$
233,298

 
$
578,744

 
$
620,777

Wholesale revenues, non-affiliates
77,017

 
78,147

 
195,364

 
215,811

Wholesale revenues, affiliates
4,232

 
9,804

 
13,596

 
25,407

Other revenues
3,874

 
4,517

 
12,513

 
13,088

Total operating revenues
305,419

 
325,766

 
800,217

 
875,083

Operating Expenses:
 
 
 
 
 
 
 
Fuel
127,576

 
157,961

 
321,664

 
402,689

Purchased power, non-affiliates
1,357

 
2,314

 
4,434

 
4,660

Purchased power, affiliates
15,683

 
8,504

 
35,386

 
36,721

Other operations and maintenance
53,541

 
65,851

 
168,937

 
200,730

Depreciation and amortization
21,136

 
19,668

 
66,134

 
59,876

Taxes other than income taxes
19,975

 
18,297

 
60,312

 
53,029

Total operating expenses
239,268

 
272,595

 
656,867

 
757,705

Operating Income
66,151

 
53,171

 
143,350

 
117,378

Other Income and (Expense):
 
 
 
 
 
 
 
Allowance for equity funds used during construction
17,763

 
7,291

 
43,460

 
15,413

Interest income
143

 
167

 
643

 
910

Interest expense, net of amounts capitalized
(9,735
)
 
(3,856
)
 
(30,563
)
 
(15,401
)
Other income (expense), net
2,441

 
257

 
1,660

 
(759
)
Total other income and (expense)
10,612

 
3,859

 
15,200

 
163

Earnings Before Income Taxes
76,763

 
57,030

 
158,550

 
117,541

Income taxes
21,705

 
18,578

 
42,344

 
38,323

Net Income
55,058

 
38,452

 
116,206

 
79,218

Dividends on Preferred Stock
433

 
433

 
1,299

 
1,299

Net Income After Dividends on Preferred Stock
$
54,625

 
$
38,019

 
$
114,907


$
77,919

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
(in thousands)
Net Income After Dividends on Preferred Stock
$
54,625

 
$
38,019

 
$
114,907

 
$
77,919

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Changes in fair value, net of tax of $-, $(5,630), $(296) and $(5,624), respectively
1

 
(9,090
)
 
(477
)
 
(9,079
)
Reclassification adjustment for amounts included in net income, net of tax of $131, $-, $279 and $-, respectively
212

 
—

 
450

 
—

Total other comprehensive income (loss)
213

 
(9,090
)
 
(27
)
 
(9,079
)
Comprehensive Income
$
54,838

 
$
28,929

 
$
114,880

 
$
68,840

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,
 
2012
 
2011
 
(in thousands)
Operating Activities:
 
 
 
Net income
$
116,206

 
$
79,218

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
65,902

 
64,329

Deferred income taxes
8,527

 
35,225

Investment tax credits received
38,811

 
51,761

Allowance for equity funds used during construction
(43,460
)
 
(15,413
)
Pension, postretirement, and other employee benefits
6,700

 
3,327

Hedge settlements
(15,983
)
 
—

Stock based compensation expense
1,718

 
1,302

Other, net
(4,834
)
 
(7,642
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
(17,622
)
 
(5,295
)
-Fossil fuel stock
(19,888
)
 
2,345

-Materials and supplies
(2,683
)
 
(1,442
)
-Prepaid income taxes
2,517

 
(18,762
)
-Other current assets
(14,652
)
 
2,295

-Accounts payable
13,581

 
21,711

-Accrued taxes
2,361

 
(3,751
)
-Accrued compensation
(4,830
)
 
(4,514
)
-Over recovered regulatory clause revenues
10,982

 
(17,754
)
-Other current liabilities
14,526

 
(296
)
Net cash provided from operating activities
157,879

 
186,644

Investing Activities:
 
 
 
Property additions
(1,169,653
)
 
(605,710
)
Cost of removal, net of salvage
(3,092
)
 
(6,931
)
Construction payables
97,360

 
70,909

Capital grant proceeds
10,058

 
139,921

Distribution of restricted cash
—

 
50,000

Other investing activities
(12,891
)
 
(3,399
)
Net cash used for investing activities
(1,078,218
)
 
(355,210
)
Financing Activities:
 
 
 
Proceeds —
 
 
 
Capital contributions from parent company
429,272

 
199,782

Senior notes issuances
600,000

 
—

Interest-bearing refundable deposit related to asset sale
150,000

 
—

Other long-term debt issuances
25,613

 
115,000

Redemptions —
 
 
 
Capital leases
(633
)
 
(1,067
)
Other long-term debt
(205,000
)
 
(130,000
)
Payment of preferred stock dividends
(1,299
)
 
(1,299
)
Payment of common stock dividends
(80,100
)
 
(56,625
)
Other financing activities
7,597

 
(377
)
Net cash provided from financing activities
925,450

 
125,414

Net Change in Cash and Cash Equivalents
5,111

 
(43,152
)
Cash and Cash Equivalents at Beginning of Period
211,585

 
160,779

Cash and Cash Equivalents at End of Period
$
216,696

 
$
117,627

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (paid $45,079 and $19,092, net of $22,131 and $5,136
capitalized for 2012 and 2011, respectively)
$
22,948

 
$
13,956

Income taxes, net
(11,737
)
 
(33,276
)
Noncash transactions—accrued property additions at end of period
233,262

 
109,732

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,
2012
 
At December 31,
2011
 
 
(in thousands)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
216,696

 
$
211,585

Receivables —
 
 
 
 
Customer accounts receivable
 
42,929

 
32,551

Unbilled revenues
 
31,234

 
27,239

Other accounts and notes receivable
 
4,041

 
7,080

Affiliated companies
 
30,786

 
23,078

Accumulated provision for uncollectible accounts
 
(503
)
 
(547
)
Fossil fuel stock, at average cost
 
160,060

 
140,173

Materials and supplies, at average cost
 
33,471

 
30,787

Other regulatory assets, current
 
51,134

 
69,201

Prepaid income taxes
 
254,084

 
37,793

Other current assets
 
5,635

 
8,881

Total current assets
 
829,567

 
587,821

Property, Plant, and Equipment:
 
 
 
 
In service
 
2,981,799

 
2,902,240

Less accumulated provision for depreciation
 
1,062,588

 
1,019,251

Plant in service, net of depreciation
 
1,919,211

 
1,882,989

Construction work in progress
 
2,077,283

 
955,135

Total property, plant, and equipment
 
3,996,494

 
2,838,124

Other Property and Investments
 
4,464

 
6,520

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
44,901

 
25,009

Other regulatory assets, deferred
 
195,381

 
185,694

Other deferred charges and assets
 
48,715

 
28,674

Total deferred charges and other assets
 
288,997

 
239,377

Total Assets
 
$
5,119,522

 
$
3,671,842

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,
2012
 
At December 31,
2011
 
 
(in thousands)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
150,613

 
$
240,633

Interest-bearing refundable deposit related to asset sale
 
150,000

 
—

Accounts payable —
 
 
 
 
Affiliated
 
73,755

 
62,650

Other
 
267,166

 
168,309

Customer deposits
 
14,105

 
13,658

Accrued taxes —
 
 
 
 
Accrued income taxes
 
5,569

 
3,813

Other accrued taxes
 
54,722

 
53,825

Accrued interest
 
28,764

 
12,750

Accrued compensation
 
11,058

 
15,889

Other regulatory liabilities, current
 
6,395

 
5,779

Over recovered regulatory clause liabilities
 
71,484

 
60,502

Liabilities from risk management activities
 
13,018

 
54,127

Other current liabilities
 
16,591

 
17,533

Total current liabilities
 
863,240

 
709,468

Long-term Debt
 
1,616,524

 
1,103,596

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
380,030

 
270,397

Deferred credits related to income taxes
 
10,329

 
11,058

Accumulated deferred investment tax credits
 
286,097

 
109,761

Employee benefit obligations
 
163,471

 
161,065

Other cost of removal obligations
 
139,371

 
126,424

Other regulatory liabilities, deferred
 
58,610

 
60,848

Other deferred credits and liabilities
 
52,550

 
37,228

Total deferred credits and other liabilities
 
1,090,458

 
776,781

Total Liabilities
 
3,570,222

 
2,589,845

Redeemable Preferred Stock
 
32,780

 
32,780

Common Stockholder's Equity:
 
 
 
 
Common stock, without par value —
 
 
 
 
Authorized —1,130,000 shares
 
 
 
 
Outstanding—1,121,000 shares
 
37,691

 
37,691

Paid-in capital
 
1,127,378

 
694,855

Retained earnings
 
360,375

 
325,568

Accumulated other comprehensive loss
 
(8,924
)
 
(8,897
)
Total common stockholder's equity
 
1,516,520

 
1,049,217

Total Liabilities and Stockholder's Equity
 
$
5,119,522

 
$
3,671,842

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 2012 vs. THIRD QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electricity 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 selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. In addition, Mississippi Power is currently constructing the Kemper IGCC. Mississippi Power has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
On June 22, 2012, the Mississippi PSC denied the proposed Certificated New Plant-A (CNP-A) rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSC's issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSC's June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Power's request for interim rates under bond while the Mississippi Supreme Court decides Mississippi Power's appeal of the Mississippi PSC's June 22, 2012 decision. On September 13, 2012, the Mississippi PSC filed the record in the appeal of the Mississippi PSC's June 22, 2012 decision with the Mississippi Supreme Court. If the Mississippi Supreme Court does not render a decision within 180 days of the filing of the record, the rates proposed on June 14, 2012 will go into effect, subject to refund by Mississippi Power. The ultimate outcome of this matter cannot be determined at this time.
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 return. In addition to the PEP performance indicators, Mississippi Power focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Mississippi Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$16.6
 
43.7
 
$37.0
 
47.5
Mississippi Power's net income after dividends on preferred stock for the third quarter 2012 was $54.6 million compared to $38.0 million for the corresponding period in 2011. The increase in net income after dividends on preferred stock for the third quarter 2012 was the result of an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, a decrease in operations and maintenance expenses, and an increase in territorial base revenues primarily due to a wholesale base rate increase effective April 1, 2012, partially offset by an increase in interest expense, net of amounts capitalized.

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

Mississippi Power's net income after dividends on preferred stock for year-to-date 2012 was $114.9 million compared to $77.9 million for the corresponding period in 2011. The increase in net income after dividends on preferred stock for year-to-date 2012 was primarily due to an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, a decrease in operations and maintenance expenses, and an increase in territorial base revenues primarily due to a wholesale base rate increase effective April 1, 2012. These factors were partially offset by an increase in depreciation and amortization and an increase in interest expense, net of amounts capitalized.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements herein for additional information regarding the Kemper IGCC.
Retail Revenues
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(13.0)
 
(5.6)
 
$(42.1)
 
(6.8)
In the third quarter 2012, retail revenues were $220.3 million compared to $233.3 million for the corresponding period in 2011. For year-to-date 2012, retail revenues were $578.7 million compared to $620.8 million for the corresponding period in 2011.
Details of the change to retail revenues were as follows:
 
 
Third Quarter
2012
 
Year-to-Date
2012
 
 
(in millions)
 
(% change)
 
(in millions)
 
(% change)
Retail – prior year
 
$
233.3

 
 
 
$
620.8

 
 
Estimated change in –
 
 
 
 
 
 
 
 
Rates and pricing
 
(0.1
)
 
(0.1
)
 
(1.9
)
 
(0.3
)
Sales growth (decline)
 
1.2

 
0.5

 
6.3

 
1.0

Weather
 
(2.6
)
 
(1.1
)
 
(10.3
)
 
(1.7
)
Fuel and other cost recovery
 
(11.5
)
 
(4.9
)
 
(36.2
)
 
(5.8
)
Retail – current year
 
$
220.3

 
(5.6
)%
 
$
578.7

 
(6.8
)%
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to decreases of $0.1 million and $1.9 million, respectively, related to the ECO Plan rate.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" herein for additional information.
Revenues attributable to changes in sales increased in the third quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted KWH energy sales to residential and commercial customers increased 2.2% and 1.8%, respectively, when compared to the corresponding period in 2011 due to a small increase in the number of residential customers and slightly improving economic conditions. KWH energy sales to industrial customers decreased 4.0% due to decreased production for several larger customers.
Revenues attributable to changes in sales increased for year-to-date 2012 when compared to the corresponding period in 2011 primarily due to an increase in sales to residential, commercial, and industrial customers. KWH energy sales to industrial customers increased 1.2% due to increased production for several larger customers.

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

Weather-adjusted KWH energy sales to residential and commercial customers increased 2.3% and 1.5%, respectively, when compared to the corresponding period in 2011. The increase in residential and commercial sales was primarily due to a small increase in the number of residential customers and slightly improving economic conditions.
Revenues attributable to changes in weather decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to milder weather.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily as a result of lower recoverable fuel costs, partially offset by an increase in revenues related to the retail portion of ad valorem taxes. 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. The retail portion of ad valorem tax expense is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.
Wholesale Revenues – Non-Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(1.1)
 
(1.4)
 
$(20.4)
 
(9.5)
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the third quarter 2012, wholesale revenues from non-affiliates were $77.0 million compared to $78.1 million for the corresponding period in 2011. The decrease was due to a $7.4 million decrease in energy revenues, of which $2.7 million was associated with a decrease in KWH sales due to lower demand primarily resulting from milder weather in the third quarter 2012 compared to the corresponding period in 2011 and $4.7 million was associated with lower fuel prices, partially offset by a $6.3 million increase in revenues primarily resulting from a wholesale base rate increase effective April 1, 2012.
For year-to-date 2012, wholesale revenues from non-affiliates were $195.4 million compared to $215.8 million for the corresponding period in 2011. The decrease was due to a $28.4 million decrease in energy revenues, of which $9.9 million was associated with a decrease in KWH sales due to lower demand primarily resulting from milder weather in 2012 compared to the corresponding period in 2011 and $18.5 million was associated with lower fuel prices, partially offset by an $8.0 million increase in revenues primarily resulting from a wholesale base rate increase effective April 1, 2012.
Wholesale Revenues – Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(5.6)
 
(56.8)
 
$(11.8)
 
(46.5)
Wholesale revenues from sales to affiliated companies within the Southern Company system 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 energy is generally sold at marginal cost.

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

In the third quarter 2012, wholesale revenues from affiliates were $4.2 million compared to $9.8 million for the corresponding period in 2011. The decrease was primarily due to a $1.0 million decrease in capacity revenues and a $4.6 million decrease in energy revenues, of which $2.3 million was associated with lower prices and $2.3 million was associated with a decrease in KWH sales.
For year-to-date 2012, wholesale revenues from affiliates were $13.6 million compared to $25.4 million for the corresponding period in 2011. The decrease was primarily due to a $1.4 million decrease in capacity revenues and a $10.4 million decrease in energy revenues, of which $8.5 million was associated with lower prices and $1.9 million was associated with a decrease in KWH sales.
Fuel and Purchased Power Expenses
 
 
Third Quarter 2012
vs.
Third Quarter 2011
 
Year-to-Date 2012
vs.
Year-to-Date 2011
 
 
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
Fuel
 
$
(30.4
)
 
(19.2
)
 
$
(81.0
)
 
(20.1
)
Purchased power – non-affiliates
 
(1.0
)
 
(41.4
)
 
(0.3
)
 
(4.8
)
Purchased power – affiliates
 
7.2

 
84.4

 
(1.3
)
 
(3.6
)
Total fuel and purchased power expenses
 
$
(24.2
)
 
 
 
$
(82.6
)
 
 
In the third quarter 2012, total fuel and purchased power expenses were $144.6 million compared to $168.8 million for the corresponding period in 2011. The decrease was primarily due to a $12.7 million decrease in the cost of fuel and purchased power and an $11.5 million decrease in total KWHs generated and purchased.
For year-to-date 2012, total fuel and purchased power expenses were $361.5 million compared to $444.1 million for the corresponding period in 2011. The decrease was primarily due to a $56.6 million decrease in the cost of fuel and purchased power and a $26.0 million decrease in total 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. See FUTURE EARNINGS POTENTIAL – "PSC Matters" herein for additional information.
Details of Mississippi Power's generation and purchased power were as follows:
 
 
Third Quarter
2012
 
Third Quarter
2011
 
Year-to-Date
2012
 
Year-to-Date
2011
Total generation (millions of KWHs)
 
3,534

 
3,990

 
9,875

 
10,579

Total purchased power (millions of KWHs)
 
523

 
267

 
1,436

 
1,149

Sources of generation (percent) –
 
 
 
 
 
 
 
 
Coal
 
35

 
44

 
29

 
42

Gas
 
65

 
56

 
71

 
58

Cost of fuel, generated (cents per net KWH) –
 
 
 
 
 
 
 
 
Coal
 
5.29

 
4.49

 
5.03

 
4.37

Gas
 
3.07

 
3.98

 
2.87

 
3.89

Average cost of fuel, generated (cents per net KWH)
 
3.91

 
4.22

 
3.55

 
4.11

Average cost of purchased power (cents per net KWH)
 
3.26

 
4.05

 
2.77

 
3.60


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

Fuel
In the third quarter 2012, fuel expense was $127.6 million compared to $158.0 million for the corresponding period in 2011. The decrease was primarily due to a 22.9% decrease in the average cost of natural gas per KWH generated primarily resulting from lower natural gas prices and a 12.9% decrease in generation from Mississippi Power's facilities resulting from lower energy demand in the third quarter 2012.
For year-to-date 2012, fuel expense was $321.7 million compared to $402.7 million for the corresponding period in 2011. The decrease was primarily due to a 26.2% decrease in the average cost of natural gas per KWH generated primarily resulting from lower natural gas prices and a 7.5% decrease in generation from Mississippi Power's facilities resulting from lower energy demand primarily due to milder weather in 2012.
Purchased Power – Non-Affiliates
In the third quarter 2012, purchased power expense from non-affiliates was $1.4 million compared to $2.3 million for the corresponding period in 2011. The decrease was primarily the result of a 62.1% decrease in the average cost of purchased power per KWH, partially offset by a 54.9% increase in the volume of KWHs purchased. The decrease in the average cost per KWH purchased was due to a lower marginal cost of fuel. The increase in the volume of KWHs purchased was due to a lower marginal cost of fuel compared to the cost of generation.
For year-to-date 2012, purchased power expense from non-affiliates was $4.4 million compared to $4.7 million for the corresponding period in 2011. The decrease was primarily the result of a 47.3% decrease in the average cost of purchased power per KWH, partially offset by an 80.5% increase in the volume of KWHs purchased. The decrease in the average cost per KWH purchased was due to a lower marginal cost of fuel. The increase in the volume of KWHs purchased was due to a lower market cost of available energy compared to the cost of generation.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the third quarter 2012, purchased power expense from affiliates was $15.7 million compared to $8.5 million for the corresponding period in 2011. The increase was primarily due to a 105.9% increase in the volume of KWHs purchased, partially offset by a 10.6% decrease in the average cost of purchased power per KWH.
For year-to-date 2012, purchased power expense from affiliates was $35.4 million compared to $36.7 million for the corresponding period in 2011. The decrease was primarily due to a 17.9% decrease in the average cost of purchased power per KWH, partially offset by a 17.3% increase in the volume of KWHs purchased.
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, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(12.4)
 
(18.7)
 
$(31.8)
 
(15.8)
In the third quarter 2012, other operations and maintenance expenses were $53.5 million compared to $65.9 million for the corresponding period in 2011. The decrease was primarily due to an $11.1 million decrease in rent expense and expenses under a long-term service agreement resulting from the expiration of an operating lease for Plant Daniel Units 3 and 4 in October 2011 and a $1.4 million decrease in transmission and distribution expenses primarily related to overhead line maintenance and vegetation management costs.

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

For year-to-date 2012, other operations and maintenance expenses were $168.9 million compared to $200.7 million for the corresponding period in 2011. The decrease was primarily due to a $31.6 million decrease in rent expense and expenses under a long-term service agreement resulting from the expiration of an operating lease for Plant Daniel Units 3 and 4 in October 2011 and a $3.6 million decrease in generation maintenance expenses. The decreases were partially offset by a $3.1 million increase in administrative and general expenses.
See Notes 1 and 7 to the financial statements of Mississippi Power under "Purchase of the Plant Daniel Combined Cycle Generating Units" and "Long-Term Service Agreements," respectively, in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$1.4
 
7.5
 
$6.2
 
10.5
In the third quarter 2012, depreciation and amortization was $21.1 million compared to $19.7 million for the corresponding period in 2011. The increase was primarily due to a $3.3 million increase in depreciation on additional plant in service and a $1.9 million increase in amortization resulting from the plant acquisition adjustment related to the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $2.0 million decrease in amortization primarily resulting from a regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4 and a $1.5 million decrease in ECO Plan amortization.
For year-to-date 2012, depreciation and amortization was $66.1 million compared to $59.9 million for the corresponding period in 2011. The increase was primarily due to a $10.0 million increase in depreciation on additional plant in service and a $5.8 million increase in amortization resulting from the plant acquisition adjustment related to the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $6.4 million decrease in amortization primarily resulting from a regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4, a $1.8 million decrease in amortization resulting from a regulatory deferral associated with operations and maintenance expenses that ended in 2011, and a $1.5 million decrease in ECO Plan amortization.
See Note 1 to the financial statements of Mississippi Power under "Purchase of the Plant Daniel Combined Cycle Generating Units" and "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.
Taxes Other Than Income Taxes
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$1.7
 
9.2
 
$7.3
 
13.7
In the third quarter 2012, taxes other than income taxes were $20.0 million compared to $18.3 million for the corresponding period in 2011. The increase was primarily due to a $2.5 million increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4, partially offset by a $0.4 million decrease in franchise taxes and a $0.4 million decrease in payroll taxes.
For year-to-date 2012, taxes other than income taxes were $60.3 million compared to $53.0 million for the corresponding period in 2011. The increase was primarily due to a $9.2 million increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4, partially offset by a $1.8 million decrease in franchise taxes.
The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.

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

Allowance for Equity Funds Used During Construction
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$10.5
 
143.6
 
$28.1
 
182.0
In the third quarter 2012, AFUDC equity was $17.8 million compared to $7.3 million for the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $43.5 million compared to $15.4 million for the corresponding period in 2011. These increases were primarily due to the construction of 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 FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Other Income (Expense), Net
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$2.1
 
N/M
 
$2.5
 
N/M
N/M - Not meaningful
In the third quarter 2012, other income (expense), net was $2.4 million compared to $0.3 million for the corresponding period in 2011. For year-to-date 2012, other income (expense), net was $1.7 million compared to $(0.8) million for the corresponding period in 2011. These increases were primarily due to a $2.0 million gain on the sale of property.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$5.8
 
152.5
 
$15.2
 
98.4
In the third quarter 2012, interest expense, net of amounts capitalized was $9.7 million compared to $3.9 million for the corresponding period in 2011. Capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC in the third quarter 2012 was $9.7 million compared to $2.6 million for the corresponding period in 2011. The increase in interest expense, net of amounts capitalized was primarily due to a $12.2 million increase in interest expense associated with the issuances of new long-term debt in October 2011, March 2012, and August 2012 and a $3.8 million increase in interest expense resulting from the receipt of a $150.0 million interest-bearing refundable deposit from SMEPA in March 2012 related to its pending purchase of an undivided interest in the Kemper IGCC. The increase was partially offset by a $7.1 million increase in capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC and a $1.9 million decrease in interest expense resulting from the amortization of the fair value adjustment on the assumed debt related to the purchase of Plant Daniel Units 3 and 4 in October 2011.
For year-to-date 2012, interest expense, net of amounts capitalized was $30.6 million compared to $15.4 million for the corresponding period in 2011. Capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC for year-to-date 2012 was $22.1 million compared to $5.1 million for the corresponding period in 2011. The increase in interest expense, net of amounts capitalized was primarily due to a $32.0 million increase in interest expense associated with the issuances of new long-term debt in October 2011, March 2012, and August 2012 and an $8.6 million increase in interest expense resulting from the receipt of a $150.0 million interest-bearing refundable deposit from SMEPA in March 2012 related to its pending purchase of an undivided interest in the Kemper IGCC. The increase was partially offset by a $17.0 million increase in capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC, a $5.7 million decrease in interest expense

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

resulting from the amortization of the fair value adjustment on the assumed debt related to the purchase of Plant Daniel Units 3 and 4 in October 2011, and a $2.1 million decrease in interest expense associated with the redemption of long-term debt in 2012.
See Note 1 to the financial statements of Mississippi Power under "Purchase of the Plant Daniel Combined Cycle Generating Units" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.
Income Taxes
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$3.1
 
16.8
 
$4.0
 
10.5
In the third quarter 2012, income taxes were $21.7 million compared to $18.6 million for the corresponding period in 2011. The increase was primarily due to a $7.9 million increase resulting from higher pre-tax earnings, partially offset by a $4.0 million decrease resulting from higher AFUDC equity, which is non-taxable, a $0.3 million decrease in unrecognized tax benefits, and a $0.5 million decrease due to the actualization of the 2011 tax return in the third quarter 2012.
For year-to-date 2012, income taxes were $42.3 million compared to $38.3 million for the corresponding period in 2011. The increase was primarily due to a $15.8 million increase resulting from higher pre-tax earnings and a $1.0 million increase due to lower State of Mississippi manufacturing investment tax credits, partially offset by a $10.7 million decrease resulting from higher AFUDC equity, which is non-taxable, a $1.5 million decrease in unrecognized tax benefits, and a $0.5 million decrease due to the actualization of the 2011 tax return in the third quarter 2012.
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 selling electricity. These factors include Mississippi 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. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced 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. Changes in economic conditions impact sales for Mississippi Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
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. 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 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.

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New Source Review Actions
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to the unit co-owned by Mississippi Power). The U.S. District Court for the Northern District of Alabama has not ruled on the EPA's motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.
Climate Change Litigation
Kivalina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. On October 8, 2012, the plaintiffs filed for review of the decision by the U.S. Court of Appeals for the Ninth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
General
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power's estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Mississippi Power's preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA's final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA's proposed water and coal combustion byproducts rules.
Mississippi Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA's proposed water and coal combustion byproducts rules. While the final MATS compliance plan is still being developed and the ultimate costs remain uncertain, compliance decisions made in 2012 have allowed Mississippi Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $430 million to approximately $55 million as follows: 
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
MATS rule
 
$
—

 
$
5

 
$
50


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In addition, Mississippi Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $121 million to approximately $40 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows: 
 
 
2012
 
2013
 
2014
 
 
 
 
(in millions)
 
 
Proposed water and coal combustion byproducts rules
 
$
1

 
$
10

 
$
30

While Mississippi Power's ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Mississippi Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $1 billion to $2 billion range provided in the Form 10-K. Included in this amount is approximately $354 million that is also included in the 2012 through 2014 base level capital investment of Mississippi Power described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Mississippi Power's ultimate compliance strategy and actual future environmental capital expenditures are dependent on development of the final MATS compliance plan and will be affected by the final requirements of new or revised environmental regulations that are promulgated; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Mississippi Power's fuel mix. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, and changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone and fine particulate matter air quality standards, the MATS rule, the Cross-State Air Pollution Rule (CSAPR), and the Clean Air Visibility Rule (CAVR).
On May 21, 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Mississippi Power's service territory were designated as nonattainment areas.
On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Mississippi Power's service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Mississippi Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.

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On August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety and directed the EPA to continue to administer the Clean Air Interstate Rule pending the EPA's development of a valid replacement. The vacatur of CSAPR creates additional uncertainty with respect to whether additional controls may be required for CAVR and best available retrofit technology compliance. On October 5, 2012, the EPA filed for review of the decision by the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter depends on the outcome of any legal challenges and further action by the EPA and cannot be determined at this time.
On August 29, 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized, the revisions would apply the NSPS to all new, reconstructed, and modified CTs, including CTs at combined cycle units, during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and 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 Mississippi Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Byproducts
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Mississippi Power in Item 7 of the Form 10-K for additional information. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts. 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 April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA's actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.

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FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" and "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and 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 for additional information.
On January 20, 2012, Mississippi Power reached a settlement agreement with its wholesale customers, which was executed by all parties on March 9, 2012. The settlement agreement provides that base rates under the cost-based electric tariff will increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. In 2012, the amount of base rate revenues to be received from the agreed upon increase will be approximately $17.0 million. On March 12, 2012, Mississippi Power filed an unopposed motion to place wholesale Municipal and Rural Associations (MRA) interim rates into effect pending approval of the settlement agreement between the parties by the FERC. On March 28, 2012, the FERC approved the motion to place interim rates into effect beginning in May 2012. On September 27, 2012, Mississippi Power, with its wholesale customers, filed a final settlement agreement with the FERC. On November 5, 2012, the settlement judge certified the settlement agreement to the FERC with the recommendation that it be approved. A decision by the FERC is expected by the end of 2012. The ultimate outcome of this matter cannot be determined at this time.
PSC Matters
General
On August 7, 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing for informational purposes only the ROE formulas used by Mississippi Power and all other regulated electric utilities in Mississippi. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Performance Evaluation Plan" of Mississippi Power in Item 7 and 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 April 2, 2012, Mississippi Power filed a motion to suspend the 2011 PEP lookback filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing also impact the 2011 PEP lookback filing, making it impractical to determine Mississippi Power's actual retail return on investment for 2011 for purposes of the 2011 PEP lookback filing. An order granting the suspension of the 2011 PEP lookback was signed by the Mississippi PSC on May 8, 2012. While Mississippi Power does not expect the resolution of these unresolved matters to have a material impact on its financial statements, the ultimate outcome of these matters cannot be determined at this time.
Environmental Compliance Overview Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC.

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On February 14, 2012, Mississippi Power submitted its 2012 ECO Plan filing, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2, Mississippi Power revised the 2012 ECO Plan filing to exclude scrubber expenditures from rate base, which resulted in a 0.16% decrease in annual revenues. On June 22, 2012, the 2012 ECO Plan filing, including the proposed rate decrease, was approved by the Mississippi PSC, effective on June 29, 2012.
On April 3, 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan. As of September 30, 2012, total project expenditures were $118.4 million, with Mississippi Power's portion being $59.2 million. The ultimate outcome of this matter cannot be determined at this time.
Certificated New Plant
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Certificated New Plant" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Certificated New Plant" in Item 8 of the Form 10-K and "Integrated Coal Gasification Combined Cycle" herein for additional information.
On May 23, 2012, the Mississippi Public Utilities Staff signed a joint stipulation with Mississippi Power to establish a new rate schedule for CNP-A, a proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. An amended and restated stipulation was subsequently executed and filed on June 1, 2012. On June 14, 2012, Mississippi Power submitted to the Mississippi PSC a proposed supplemental compliance filing to establish the new CNP-A rate schedule and a stipulated rate increase based upon the revenue request of between $55.3 million and $58.6 million to recover financing costs over the remainder of 2012.
On June 22, 2012, the Mississippi PSC denied the proposed CNP-A rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSC's issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSC's June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Power's request for interim rates under bond while the Mississippi Supreme Court decides Mississippi Power's appeal of the Mississippi PSC's June 22, 2012 decision.
On September 13, 2012, the Mississippi PSC filed the record in the appeal of the Mississippi PSC's June 22, 2012 decision with the Mississippi Supreme Court. If the Mississippi Supreme Court does not render a decision within 180 days of the filing of the record, the rates proposed on June 14, 2012 will go into effect, subject to refund by Mississippi Power.
The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Mississippi Power in Item 7 and 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 information regarding Mississippi Power's fuel cost recovery.

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At September 30, 2012, the amount of over recovered retail fuel costs included in Mississippi Power's Condensed Balance Sheets herein was $52.8 million compared to $42.4 million at December 31, 2011. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At September 30, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Power's Condensed Balance Sheets herein was $16.8 million and $2.1 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at September 30, 2012, the amount of under recovered MRA emissions allowance cost included in Mississippi Power's Condensed Balance Sheets herein was $0.2 million. At December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power's Condensed Balance Sheets herein was $1.7 million. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, any changes in the billing factors will not have a significant effect on Mississippi Power's revenues or net income, but will affect annual cash flow.
Storm Damage Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Storm Damage Cost Recovery" in Item 8 in the Form 10-K for information regarding Mississippi Power's storm damage cost recovery. In August 2012, Hurricane Isaac hit the Gulf Coast of the United States and caused damage within Mississippi Power's service area. The estimated total storm restoration costs relating to Hurricane Isaac through September 30, 2012 were $9.7 million. Mississippi Power maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and generally the cost of uninsured damage to its generation facilities and other property. At September 30, 2012, the balance in the storm reserve was $58.7 million.
Integrated Coal Gasification Combined Cycle
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and 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.
In May 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the Mississippi PSC order confirming Mississippi Power's application for a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. In June 2010, the Mississippi PSC issued the CPCN (2010 MPSC Order).
In June 2010, the Sierra Club filed an appeal of the Mississippi PSC's June 2010 decision to grant the CPCN for the Kemper IGCC with the Chancery Court. Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club's direct appeal. In February 2011, the Chancery Court issued a judgment affirming the 2010 MPSC Order and, in March 2011, the Sierra Club appealed the Chancery Court's decision to the Mississippi Supreme Court. On March 15, 2012, the Mississippi Supreme Court reversed the Chancery Court's decision and the 2010 MPSC Order and remanded the matter to the Mississippi PSC to correct the 2010 MPSC Order. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN.
On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC. On April 24, 2012, the Mississippi PSC issued a detailed order on remand (2012 MPSC Order) confirming the CPCN for the Kemper IGCC subject to the same conditions set forth in the 2010 MPSC Order. On April 26, 2012, the Sierra Club filed a motion for stay and a notice of appeal of the 2012 MPSC Order with the Chancery Court. On May 18, 2012, Mississippi Power's motion to join the appeal was approved. On August 7, 2012, the Sierra Club withdrew its motion for stay.

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The certificated cost estimate of the Kemper IGCC is $2.4 billion, net of $245.3 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2) and excluding the cost of the lignite mine and equipment and the carbon dioxide (CO2) pipeline facilities. The 2012 MPSC Order, like the 2010 MPSC Order, (1) approved a construction cost cap of up to $2.88 billion (exemptions from the cost cap include the cost of the lignite mine and equipment, the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital, which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on the ratepayers, relative to the original proposal), (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's proposal, and (3) approved financing cost recovery on CWIP balances not to exceed the certificated cost estimate, which provided for the accrual of AFUDC in 2010 and 2011 and provides for the current recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the Kemper IGCC).
Mississippi Power's current cost estimate for the Kemper IGCC equals the $2.88 billion cost cap, including a $40 million to $50 million contingency. The Mississippi PSC and the Mississippi Public Utilities Staff have engaged their independent monitors to assess the current cost estimates and schedule projections for the Kemper IGCC. These consultants are issuing reports with their own opinions as to the likelihood that costs for the Kemper IGCC will remain under the $2.88 billion cost cap and as to the expected in-service date. While Mississippi Power continues to believe its cost estimate and schedule projection remain appropriate based on the current status of the project, it is possible that Mississippi Power will experience further cost increases and/or schedule delays with respect to the Kemper IGCC. Certain factors have caused and may continue to cause the costs for the Kemper IGCC to increase and/or schedule delays to occur including, but not limited to, costs and productivity of labor, adverse weather conditions, shortages and inconsistent quality of equipment, materials and labor, contractor or supplier delay or non-performance under construction or other agreements, and unforeseen engineering problems. To the extent that costs beyond any permitted exceptions to the cost cap exceed $2.88 billion or the Mississippi PSC disallows a portion of the costs relating to the Kemper IGCC, including financing costs, charges to expense may occur and these charges could be material.
The Kemper IGCC, expected to be in service in May 2014, will use locally mined lignite (an abundant, lower heating value coal) from a mine adjacent to the Kemper IGCC as fuel. The mine is scheduled to be placed into service in June 2013. In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County. The estimated capital cost of the mine is approximately $245 million, of which $127 million has been incurred through September 30, 2012.
In May 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a wholly-owned subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. Because Liberty Fuels conducts all of its activities on behalf of Mississippi Power, Liberty Fuels qualifies as a variable interest entity for which Mississippi Power is the primary beneficiary. The contract with Liberty Fuels is effective 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. Consistent with the requirements of consolidation accounting, Liberty Fuels is consolidated in the financial statements of Mississippi Power and accordingly the asset retirement cost and the ARO have been recorded in Mississippi Power's financial statements. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

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In December 2011, the Mississippi Department of Environmental Quality (MDEQ) approved the surface coal mining and the water pollution control permits for the mining operations operated by Liberty Fuels. On January 12, 2012, two individuals each filed a notice of appeal and a request for evidentiary hearing with the MDEQ regarding the surface coal mining and water pollution control permits. On March 8, 2012, the MDEQ permit board affirmed its issuance of the surface coal mining and water pollution control permits.
In 2009, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $133 million of Internal Revenue Code Section 48A tax credits (Phase I) to Mississippi Power. In April 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the rules for Section 48A investment tax credits. Through September 30, 2012, Mississippi Power received or accrued tax benefits totaling $276.8 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. On October 15, 2012, Mississippi Power filed an application with the DOE for certification of the Kemper IGCC for additional tax credits under the Internal Revenue Code Section 48A (Phase III). A portion of the tax credits realized by Mississippi Power may be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC. Based on current tax laws and regulations in effect, Mississippi Power expects to receive substantially all of the tax credits accrued through September 30, 2012 by September 30, 2013.
In July 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In December 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval of SMEPA's 17.5% undivided interest in the Kemper IGCC. On February 28, 2012, the Mississippi PSC approved the joint petition for the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. On June 29, 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012 and reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC, subject to approval by the Mississippi PSC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. On September 27, 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposit has been presented as a current liability in Mississippi Power's Condensed Balance Sheet herein and as financing proceeds in Mississippi Power's Condensed Statement of Cash Flows herein.
As of September 30, 2012, Mississippi Power had spent a total of $2.1 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO2 pipeline facilities, and regulatory filing costs. Of this total, $2.0 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $30.2 million was recorded in other regulatory assets, $3.0 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

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

The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. Of the total costs of $51 million incurred through March 2009, $46 million has been reviewed and deemed prudent by the Mississippi PSC in the 2010 MPSC Order and again in the 2012 MPSC Order. A decision regarding the remaining $5 million has not been issued. The timing of the review of the remaining Kemper IGCC costs has not been determined.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Certificated New Plant" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Certificated New Plant" in Item 8 of the Form 10-K and "PSC Matters – Certificated New Plant" herein for information on the proposed rate schedules related to the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013). Due to the significant amount of estimated bonus depreciation for 2012, the utilization of a portion of Mississippi Power's tax credits has been delayed. Mississippi Power expects to receive substantially all of the tax credits accrued through September 30, 2012 by September 30, 2013.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.
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 increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, 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 the Notes 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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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power's financial condition remained stable at September 30, 2012. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
Net cash provided from operating activities totaled $157.9 million for the first nine months of 2012, a decrease of $28.8 million as compared to the corresponding period in 2011. The decrease in cash provided from operating activities is primarily due to a decrease in deferred income taxes, a decrease in hedge settlements, an increase in fossil fuel stock, and a decrease in cash related to accounts payable and receivables. The decrease was partially offset by an increase in regulatory clause revenues primarily due to lower fuel costs, an increase in prepaid income taxes, and an increase in other current liabilities primarily due to accrued interest. Net cash used for investing activities totaled $1.1 billion for the first nine months of 2012 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $925.5 million for the first nine months of 2012 primarily due to the issuances of senior notes and capital contributions from Southern Company. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities. 
Significant balance sheet changes for the first nine months of 2012 include an increase in prepaid income taxes of $216.3 million and an increase in accumulated deferred investment tax credits of $176.3 million primarily due to the Kemper IGCC investment tax credit. Total property, plant, and equipment increased $1.2 billion primarily due to the increase in CWIP related to the Kemper IGCC. Interest-bearing refundable deposit related to an asset sale increased $150.0 million due to the receipt of the $150.0 million interest-bearing refundable deposit from SMEPA. Long-term debt increased $512.9 million primarily due to the issuance of $600.0 million of senior notes, partially offset by the redemption of $90.0 million of senior notes. Paid-in capital increased $432.5 million primarily due to $425.0 million of capital contributions from Southern Company.

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

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 to comply with existing environmental regulations, 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 $151 million will be required through September 30, 2013 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL – "Environmental Statutes and Regulations – General" herein for a description of Mississippi Power's estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.
See Note 7 to the financial statements of Mississippi Power in Item 8 of the Form 10-K for information on Mississippi Power's construction program. The construction program of Mississippi Power is currently estimated to include a base level investment of $1.8 billion, $713 million, and $423 million for 2012, 2013, and 2014, respectively. Included in these estimated amounts are expenditures related to the Kemper IGCC of $1.6 billion, $473 million, and $145 million in 2012, 2013, and 2014, respectively, which include additional AFUDC due to the delay in the rate recovery and are net of SMEPA's 15% expected ownership share of the Kemper IGCC of approximately $470 million and $14 million in 2013 and 2014, respectively. See FUTURE EARNINGS POTENTIAL  – "PSC Matters – Certificated New Plant" and "Integrated Coal Gasification Combined Cycle" 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 environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi 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
Except as described below with respect to potential DOE loan guarantees, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily funds from operating cash flows, security issuances, term loans, short-term debt, 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. During the first nine months of 2012, Mississippi Power received $425 million in capital contributions from Southern Company. On October 29, 2012, Mississippi Power received $150 million in additional capital contributions from Southern Company. On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA towards its pending purchase of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 9.967% per annum at September 30, 2012. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Mississippi Power in Item 7 of the Form 10-K for additional information.

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

Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees to Mississippi Power. In the event that the DOE does not issue a conditional commitment or a final definitive loan guarantee, Mississippi Power expects to finance the construction of the Kemper IGCC through traditional capital markets financings. Mississippi Power has received $245.3 million in DOE CCPI2 grant funds that were used for the construction of the Kemper IGCC. An additional $25 million in CCPI2 grant funds is expected to be received for the initial operation of the Kemper IGCC.
Mississippi Power's current liabilities sometimes 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 cash needs, which can fluctuate significantly due to the seasonality of the business.
At September 30, 2012, Mississippi Power had approximately $216.7 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2012, including expiration dates, were as follows: 
Expires
 
 
 
Executable Term
Loans
 
Due Within One
Year(a)
2012
 
2013
 
2014
 
Total
 
Unused
 
    One
    Year

 
Two    
Years    

 
    Term
    Out

 
No Term
Out

(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
$
16

 
$
120

 
$
165

 
$
301

 
$
301

 
$
25

 
$
41

 
$
66

 
$
70

(a)
Reflects facilities expiring on or before September 30, 2013.
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 arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Mississippi Power. Mississippi Power is currently in compliance with all such covenants. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Mississippi Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2012 was approximately $40 million.
Mississippi 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 Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power are loaned directly to Mississippi Power. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support.
During the three months ended September 30, 2012, Mississippi Power had no commercial paper or other short-term debt outstanding.
Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.

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

Credit Rating Risk
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. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At September 30, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $290 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash.
Mississippi Power also has entered into an asset purchase agreement with SMEPA for the pending purchase of an undivided interest in the Kemper IGCC that could require a refund of the $150 million deposit within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. Additionally, any credit rating downgrade could impact Mississippi Power's ability to access capital markets, particularly the short-term debt market.
On July 3, 2012, Fitch downgraded the issuer default and unsecured long-term debt ratings of Mississippi Power to A- from A and to A from A+, respectively. Fitch also announced that it had downgraded the pollution control revenue bond ratings of Mississippi Power to A from A+ and the preferred stock ratings of Mississippi Power to BBB+ from A-. Fitch revised the ratings outlook for Mississippi Power to negative from stable.
On August 6, 2012, Moody's downgraded the senior unsecured debt and preferred stock ratings of Mississippi Power to A3 from A2 and to Baa2 from Baa1, respectively. Moody's revised the ratings outlook for Mississippi Power to negative from stable.
Market Price Risk
Mississippi Power's market risk exposure relative to interest rate changes for the third quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Mississippi Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Mississippi Power continues to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power had no material change in market risk exposure for the third quarter 2012 when compared with the December 31, 2011 reporting period.

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

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and nine months ended September 30, 2012 were as follows:
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(37
)
 
$
(51
)
Contracts realized or settled
 
13

 
39

Current period changes(a)
 
9

 
(3
)
Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(15
)
 
$
(15
)
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and nine months ended September 30, 2012 were as follows: 
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
18

 
$
29

Natural gas options
 
4

 
7

Total changes
 
$
22

 
$
36

The net hedge volumes of energy-related derivative contracts were as follows:
 
 
 
September 30,
2012
 
June 30,
2012
 
December 31,
2011
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
33

 
29

 
22

Commodity – Natural gas options
 
2

 
5

 
9

Total hedge volume
 
35

 
34

 
31

The weighted average swap contract cost above market prices was approximately $0.42 per mmBtu as of September 30, 2012, $1.08 per mmBtu as of June 30, 2012, and $1.98 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the costs associated with natural gas hedges are recovered through Mississippi Power's energy cost management clause (ECM).
Regulatory hedges relate to Mississippi Power's fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Mississippi Power's ECM.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.

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

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2012 were as follows:
 
 
 
 
September 30, 2012
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(15
)
 
(11
)
 
(4
)
 
—

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(15
)
 
$
(11
)
 
$
(4
)
 
$
—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Mississippi Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Mississippi Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Mississippi Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Mississippi Power in Item 7 and Note 1 under "Financial Instruments" and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In March 2012, Mississippi Power issued $250 million aggregate principal amount of Series 2012A 4.25% Senior Notes due March 15, 2042 and an additional $150 million aggregate principal amount of Series 2011A 2.35% Senior Notes due October 15, 2016. The Series 2011A Senior Notes were of the same series of notes that were originally issued in October 2011 in the aggregate principal amount of $150 million. Upon completion of this offering, the aggregate principal amount of the outstanding Series 2011A Senior Notes was $300 million. The proceeds from the sales of the Series 2012A Senior Notes and the Series 2011A Senior Notes were used to repay a bank loan in an aggregate principal amount of $75 million and for general corporate purposes, including Mississippi Power's continuous construction program.
In March 2012, $300 million in interest rate swaps were settled, of which $250 million related to the Series 2012A Senior Notes at a loss of approximately $13.3 million, which will be amortized to interest expense, in earnings, over 10 years, and $50 million related to the Series 2011A Senior Notes at a loss of approximately $2.7 million, which will be amortized to interest expense, in earnings, over 10 years.
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 9.967% per annum at September 30, 2012, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies.
In May 2012, Mississippi Power redeemed $90 million aggregate principal amount of Series E 5-5/8% Senior Notes due May 1, 2033.

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

In August 2012, Mississippi Power issued an additional $200 million aggregate principal amount of Series 2012A 4.25% Senior Notes due March 15, 2042. The Series 2012A Senior Notes were of the same series of notes that were originally issued in March 2012 in the aggregate principal amount of $250 million. Upon completion of this offering, the aggregate principal amount of the outstanding Series 2012A Senior Notes is $450 million. The proceeds from this sale of the Series 2012A Senior Notes were used for general corporate purposes, including Mississippi Power's continuous construction program.
In August 2012, the Mississippi Business Finance Corporation entered into an agreement to issue up to $42.5 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012A (Mississippi Power Company Project), up to $21.25 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012B (Mississippi Power Company Project), and up to $21.25 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012C (Mississippi Power Company Project) for the benefit of Mississippi Power. In August 2012, the Mississippi Business Finance Corporation issued $4.36 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012B and $21.25 million aggregate principal amount of Revenue Bonds (Mississippi Power Company Project), Series 2012C for the benefit of Mississippi Power. The proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of these bonds will be used for this same purpose.
In September 2012, Mississippi Power paid at maturity a $40 million aggregate principal amount floating rate bank note.
In September 2012, Mississippi Power entered into a 366-day extension of a $125 million aggregate principal amount floating rate bank loan that bears interest based on one-month LIBOR.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi 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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SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

139
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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
(in thousands)
Operating Revenues:
 
 
 
 
 
 
 
Wholesale revenues, non-affiliates
$
239,916

 
$
274,980

 
$
558,338

 
$
705,106

Wholesale revenues, affiliates
112,705

 
85,177

 
330,443

 
239,020

Other revenues
2,350

 
2,408

 
5,676

 
5,435

Total operating revenues
354,971

 
362,565

 
894,457


949,561

Operating Expenses:
 
 
 
 
 
 
 
Fuel
126,109

 
141,968

 
306,738

 
345,841

Purchased power, non-affiliates
23,888

 
25,159

 
67,052

 
53,765

Purchased power, affiliates
2,650

 
11,423

 
7,904

 
48,700

Other operations and maintenance
40,357

 
39,571

 
128,951

 
122,372

Depreciation and amortization
37,612

 
31,558

 
103,541

 
92,530

Taxes other than income taxes
5,121

 
4,178

 
14,656

 
13,506

Total operating expenses
235,737


253,857

 
628,842

 
676,714

Operating Income
119,234

 
108,708

 
265,615

 
272,847

Other Income and (Expense):
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(17,210
)
 
(19,886
)
 
(44,801
)
 
(56,489
)
Other income (expense), net
(522
)
 
(158
)
 
(686
)
 
(359
)
Total other income and (expense)
(17,732
)
 
(20,044
)
 
(45,487
)
 
(56,848
)
Earnings Before Income Taxes
101,502

 
88,664

 
220,128

 
215,999

Income taxes
33,126

 
32,593

 
75,834

 
77,584

Net Income
$
68,376

 
$
56,071

 
$
144,294


$
138,415

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months
Ended September 30,
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
(in thousands)
Net Income
$
68,376

 
$
56,071

 
$
144,294

 
$
138,415

Other comprehensive income (loss):
 
 
 
 
 
 
 
Qualifying hedges:
 
 
 
 
 
 
 
Changes in fair value, net of tax of $215, $(135), $95 and $265, respectively
338

 
(206
)
 
152

 
402

Reclassification adjustment for amounts included in net income, net of tax of $999, $1,106, $2,911 and $3,261, respectively
1,569

 
1,685

 
4,608

 
4,946

Total other comprehensive income (loss)
1,907

 
1,479

 
4,760


5,348

Comprehensive Income
$
70,283

 
$
57,550

 
$
149,054


$
143,763

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
For the Nine Months
Ended September 30,
 
2012
 
2011
 
(in thousands)
Operating Activities:
 
 
 
Net income
$
144,294

 
$
138,415

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
112,013

 
102,756

Deferred income taxes
147,993

 
474

Convertible investment tax credits
36,308

 
62,298

Deferred revenues
9,299

 
8,114

Mark-to-market adjustments
(8,970
)
 
1,479

Other, net
1,168

 
3,790

Changes in certain current assets and liabilities —
 
 
 
-Receivables
(20,427
)
 
(24,799
)
-Fossil fuel stock
(6,440
)
 
305

-Materials and supplies
(5,557
)
 
(1,826
)
-Prepaid income taxes
(5,669
)
 
24,436

-Other current assets
(2,159
)
 
219

-Accounts payable
5,668

 
(2,634
)
-Accrued taxes
48,203

 
27,417

-Accrued interest
(10,225
)
 
(11,601
)
-Other current liabilities
808

 
(661
)
Net cash provided from operating activities
446,307

 
328,182

Investing Activities:
 
 
 
Plant acquisitions
(113,651
)
 
—

Property additions
(97,569
)
 
(200,157
)
Change in construction payables
(17,557
)
 
(14,667
)
Payments pursuant to long-term service agreements
(52,650
)
 
(46,065
)
Other investing activities
153

 
(3,211
)
Net cash used for investing activities
(281,274
)
 
(264,100
)
Financing Activities:
 
 
 
Increase (decrease) in notes payable, net
(78,059
)
 
(220,903
)
Proceeds — 
 
 
 
Capital contributions
(681
)
 
125,596

Senior Notes
—

 
300,000

Other long-term debt
4,949

 
—

Repayments — Other long-term debt
(650
)
 
(3,441
)
Payment of common stock dividends
(95,250
)
 
(68,400
)
Other financing activities
3,776

 
(5,629
)
Net cash provided from (used for) financing activities
(165,915
)
 
127,223

Net Change in Cash and Cash Equivalents
(882
)
 
191,305

Cash and Cash Equivalents at Beginning of Period
16,943

 
14,204

Cash and Cash Equivalents at End of Period
$
16,061

 
$
205,509

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $16,436 and $12,112 capitalized for 2012 and 2011, respectively)
$
46,163

 
$
65,201

Income taxes, net
(137,756
)
 
(26,555
)
Noncash transactions — accrued property additions at end of period
21,034

 
36,971

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At September 30,
2012
 
At December 31,
2011
 
 
(in thousands)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
16,061

 
$
16,943

Receivables —
 
 
 
 
Customer accounts receivable
 
73,109

 
59,360

Other accounts receivable
 
1,870

 
2,122

Affiliated companies
 
48,421

 
36,508

Fossil fuel stock, at average cost
 
19,478

 
13,038

Materials and supplies, at average cost
 
44,103

 
37,603

Prepaid service agreements—current
 
66,219

 
28,621

Prepaid income taxes
 
7,052

 
5,192

Other prepaid expenses
 
6,177

 
4,645

Assets from risk management activities
 
1,374

 
177

Total current assets
 
283,864

 
204,209

Property, Plant, and Equipment:
 
 
 
 
In service
 
3,714,129

 
3,167,840

Less accumulated provision for depreciation
 
748,336

 
652,087

Plant in service, net of depreciation
 
2,965,793

 
2,515,753

Construction work in progress
 
338,648

 
666,280

Total property, plant, and equipment
 
3,304,441

 
3,182,033

Other Property and Investments:
 
 
 
 
Goodwill
 
1,839

 
1,839

Other intangible assets, net of amortization of $2,523 and $1,476 at
  September 30, 2012 and December 31, 2011, respectively
 
46,597

 
47,644

Total other property and investments
 
48,436

 
49,483

Deferred Charges and Other Assets:
 
 
 
 
Prepaid long-term service agreements
 
110,131

 
115,838

Other deferred charges and assets — affiliated
 
2,848

 
3,029

Other deferred charges and assets — non-affiliated
 
31,887

 
26,385

Total deferred charges and other assets
 
144,866

 
145,252

Total Assets
 
$
3,781,607

 
$
3,580,977

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity
 
At September 30,
2012
 
At December 31,
2011
 
 
(in thousands)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
—

 
$
555

Notes payable — non-affiliated
 
102,403

 
179,520

Accounts payable —
 
 
 
 
Affiliated
 
67,756

 
63,609

Other
 
29,010

 
44,321

Accrued taxes —
 
 
 
 
Accrued income taxes
 
36,965

 
2,548

Other accrued taxes
 
14,062

 
2,158

Accrued interest
 
11,649

 
21,874

Liabilities from risk management activities
 
1,880

 
9,651

Other current liabilities
 
8,682

 
7,401

Total current liabilities
 
272,407

 
331,637

Long-term Debt
 
1,306,689

 
1,302,758

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
468,932

 
319,790

Deferred convertible investment tax credits
 
159,640

 
125,065

Deferred capacity revenues — affiliated
 
36,454

 
20,637

Other deferred credits and liabilities — affiliated
 
2,893

 
3,618

Other deferred credits and liabilities — non-affiliated
 
5,113

 
4,965

Total deferred credits and other liabilities
 
673,032

 
474,075

Total Liabilities
 
2,252,128

 
2,108,470

Redeemable Noncontrolling Interest
 
7,674

 
3,825

Common Stockholder's Equity:
 
 
 
 
Common stock, par value $.01 per share —
 
 
 
 
Authorized — 1,000,000 shares
 
 
 
 
Outstanding — 1,000 shares
 
—

 
—

Paid-in capital
 
1,027,529

 
1,028,210

Retained earnings
 
496,345

 
447,301

Accumulated other comprehensive loss
 
(2,069
)
 
(6,829
)
Total common stockholder's equity
 
1,521,805

 
1,468,682

Total Liabilities and Stockholder's Equity
 
$
3,781,607

 
$
3,580,977

The accompanying notes as they relate to Southern 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 2012 vs. THIRD QUARTER 2011
AND
YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 2011
OVERVIEW
Southern Power and its subsidiaries construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based prices in the wholesale market. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into PPAs primarily with investor owned utilities, independent power producers, municipalities, and electric cooperatives. In accordance with this overall growth strategy, the Nacogdoches Power, LLC (Nacogdoches) biomass plant began commercial operation on June 22, 2012. See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information. In 2012, Southern Power and Turner Renewable Energy, Inc. (TRE), through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex), Spectrum Nevada Solar, LLC (Spectrum), and Granville Solar, LLC (Granville). Upon completion of construction, these projects will add a total of 47 MWs of solar capacity to the Southern Power generation portfolio. The acquisitions are in accordance with Southern Power's overall growth strategy. See FUTURE EARNINGS POTENTIAL – "Acquisitions" herein for additional information.
To evaluate operating results and to ensure Southern Power's ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (Peak Season EFOR), contract availability, and net income. Peak Season EFOR defines the hours during peak demand times when Southern Power's generating units are not available due to forced outages (the lower the better). Contract availability measures the percentage of scheduled hours that a unit was available. Net income is the primary measure of Southern Power's financial performance. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$12.3
 
21.9
 
$5.9
 
4.2
Southern Power's net income for the third quarter 2012 was $68.4 million compared to $56.1 million for the corresponding period in 2011. The increase was primarily due to an increase in energy revenues from sales to affiliates under the IIC, an increase in capacity revenues due to an increase in total MWs of capacity under long-term contracts, lower fuel and purchased power expenses, and lower interest expense. The increase was partially offset by a decrease in energy revenues from non-affiliates and increased depreciation.
Southern Power's net income for year-to-date 2012 was $144.3 million compared to $138.4 million for the corresponding period in 2011. The increase was primarily due to an increase in energy revenues from sales to affiliates under the IIC, an increase in capacity revenues due to an increase in total MWs of capacity under long-term contracts, lower fuel and purchased power expenses, and lower interest expense. The increase was partially offset by a decrease in energy revenues from non-affiliates, an increase in other operations and maintenance expenses, and increased depreciation.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(35.1)
 
(12.8)
 
$(146.8)
 
(20.8)
Wholesale energy sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in 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.
Wholesale revenues from non-affiliates for the third quarter 2012 were $239.9 million compared to $275.0 million for the corresponding period in 2011. The decrease was primarily due to a $57.1 million decrease in energy sales, reflecting a 28.1% decrease in the average price of energy and a 5.4% decrease in KWH sales. The decrease in revenue from energy sales was partially offset by a $22.1 million increase in capacity revenue due to an increase in the total MWs of capacity under contract with non-affiliates.
Wholesale energy sales to non-affiliates for year-to-date 2012 were $558.3 million compared to $705.1 million for the corresponding period in 2011. The decrease was primarily due to a $178.4 million decrease in energy sales, reflecting a 36.4% decrease in the average price of energy and a 4.6% decrease in KWH sales. The decrease in revenue from energy sales was partially offset by a $31.6 million increase in capacity revenue due to an increase in the total MWs of capacity under contract with non-affiliates.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues – Affiliates
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$27.5
 
32.3
 
$91.4
 
38.2
Wholesale energy sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC.
Wholesale revenues from affiliates for the third quarter 2012 were $112.7 million compared to $85.2 million for the corresponding period in 2011. The increase was the result of a $27.5 million increase in energy sales under the IIC, reflecting a 121.1% increase in KWH sales resulting from the availability of Southern Power's lower priced natural gas resources to serve affiliate demand, partially offset by a 25.5% reduction in the average price of energy.
Wholesale revenues from affiliates for year-to-date 2012 were $330.4 million compared to $239.0 million for the corresponding period in 2011. The increase was primarily the result of a $114.7 million increase in energy sales under the IIC, reflecting a 252.7% increase in KWH sales resulting from the availability of Southern Power's lower priced natural gas resources to serve affiliate demand, partially offset by a 36.6% reduction in the average price of energy. The increase in revenue from energy sales was partially offset by a $20.6 million decrease in capacity revenue due to a decrease in total MWs of capacity under contract with affiliates.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information.

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Fuel and Purchased Power Expenses
 
 
Third Quarter 2012
vs.
Third Quarter 2011
 
Year-to-Date 2012
vs.
Year-to-Date 2011
 
 
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
Fuel
 
$(15.9)
 
(11.2)
 
$(39.1)
 
(11.3)
Purchased power – non-affiliates
 
(1.3)
 
(5.1)
 
13.3
 
24.7
Purchased power – affiliates
 
(8.8)
 
(76.8)
 
(40.8)
 
(83.8)
Total fuel and purchased power expenses
 
$(26.0)
 
 
 
$(66.6)
 
 
Southern Power PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is generally accompanied by an increase or decrease in related fuel revenues and does 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 market or sold to affiliates under the IIC.
Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other available 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, affiliate-owned generation, or external purchases.
In the third quarter 2012, total fuel and purchased power expenses were $152.6 million compared to $178.6 million for the corresponding period in 2011. Fuel and purchased power expenses decreased $48.0 million due to a 22.7% decrease in the average cost of fuel and a 24.9% decrease in the average cost of purchased power. The decrease was partially offset by a $22.1 million increase associated with a 12.2% net increase in the volume of KWHs generated and purchased.
For year-to-date 2012, total fuel and purchased power expenses were $381.7 million compared to $448.3 million for the corresponding period in 2011. Fuel and purchased power expenses decreased $192.8 million due to a 34.8% decrease in the average cost of fuel and a 25.7% decrease in the average cost of purchased power. The decrease was partially offset by a $126.2 million increase associated with a 29.4% net increase in the volume of KWHs generated and purchased.
In the third quarter 2012, fuel expense was $126.1 million compared to $142.0 million for the corresponding period in 2011. The decrease was due to a $39.2 million decrease associated with the cost of fuel, partially offset by a $23.3 million increase associated with the volume of KWHs generated.
For year-to-date 2012, fuel expense was $306.7 million compared to $345.8 million for the corresponding period in 2011. The decrease was due to a $167.0 million decrease associated with the cost of fuel, partially offset by a $127.9 million increase associated with the volume of KWHs generated.
In the third quarter 2012, purchased power expenses were $26.5 million compared to $36.6 million for the corresponding period in 2011. The decrease was due to an $8.8 million decrease associated with the cost of purchased power and a $1.2 million decrease associated with the volume of KWHs purchased.
For year-to-date 2012, purchased power expenses were $75.0 million compared to $102.5 million for the corresponding period in 2011. The decrease was due to a $25.8 million decrease associated with the cost of purchased power and a $1.7 million decrease associated with the volume of KWHs purchased.


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Other Operations and Maintenance Expenses
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$0.8
 
2.0
 
$6.6
 
5.4
In the third quarter 2012, other operations and maintenance expenses were $40.4 million compared to $39.6 million for the corresponding period in 2011. The change in operations and maintenance expense was not material.
For year-to-date 2012, other operations and maintenance expenses were $129.0 million compared to $122.4 million for the corresponding period in 2011. The increase was primarily due to a $5.4 million increase in administrative and general expenses due to increases in business development expenses and affiliate service company expense allocated based on load and fuel burn and a $1.5 million increase in transmission cost.
Depreciation and Amortization
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$6.0
 
19.2
 
$11.0
 
11.9
In the third quarter 2012, depreciation and amortization was $37.6 million compared to $31.6 million for the corresponding period in 2011. The increase was primarily due to a $6.7 million increase in depreciation resulting from an increase in plant in service, including the addition of the Nacogdoches biomass plant and the Apex solar facility, and a $0.6 million increase due to higher depreciation rates from a depreciation study adopted in January 2012, partially offset by a $1.2 million decrease in depreciation related to asset retirements.
For year-to-date 2012, depreciation and amortization was $103.5 million compared to $92.5 million for the corresponding period in 2011. The increase was primarily due to a $9.3 million increase in depreciation resulting from an increase in plant in service, including the addition of the Nacogdoches biomass plant and the Apex solar facility, and a $2.3 million increase due to higher depreciation rates from a depreciation study adopted in January 2012, partially offset by a $0.6 million decrease in depreciation related to asset retirements.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$(2.7)
 
(13.5)
 
$(11.7)
 
(20.7)
In the third quarter 2012, interest expense, net of amounts capitalized was $17.2 million compared to $19.9 million for the corresponding period in 2011. The decrease was primarily due to a $2.6 million expense reduction associated with the refinancing of $575 million in long-term debt in 2011 and a $0.2 million increase in capitalized interest, as compared to amounts recognized in the corresponding period in 2011, associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant.
For year-to-date 2012, interest expense, net of amounts capitalized was $44.8 million compared to $56.5 million for the corresponding period in 2011. The decrease was primarily due to a $7.0 million expense reduction associated with the refinancing of $575 million in long-term debt in 2011 and a $4.3 million increase in capitalized interest associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant.
See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.

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Income Taxes
Third Quarter 2012 vs. Third Quarter 2011
 
Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)
 
(% change)
 
(change in millions)
 
(% change)
$0.5
 
1.6
 
$(1.8)
 
(2.3)
In the third quarter 2012, income taxes were $33.1 million compared to $32.6 million for the corresponding period in 2011. The increase was primarily due to a $4.7 million increase associated with higher pre-tax earnings, partially offset by a $3.2 million decrease related to an increase in investment tax credits (ITCs) recognized, primarily associated with the acquisition of Apex, and a $1.2 million decrease due to an increase in state ITCs as compared to the corresponding period in 2011.
For year-to-date 2012, income taxes were $75.8 million compared to $77.6 million for the corresponding period in 2011. The decrease was primarily due to a $2.2 million decrease due to the conclusion of prior year IRS audits and a $2.0 million decrease related to an increase in ITCs recognized, partially offset by a $0.5 million increase associated with higher pre-tax earnings and a $1.6 million increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid.
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 target market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. General economic conditions have lowered demand and have negatively impacted capacity revenues under Southern Power's PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery is uncertain and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
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, 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 regulatory or legislative changes cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Climate Change Litigation
Kivalina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Climate Change Litigation – Kivalina Case” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Environmental Matters – Climate Change Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. On October 8, 2012, the plaintiffs filed for review of the decision by the U.S. Court of Appeals for the Ninth Circuit. The ultimate outcome of this matter cannot be determined at this time.
Hurricane Katrina Case
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under "Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed in May 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.
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 Power in Item 7 of the Form 10-K for additional information on the Cross-State Air Pollution Rule (CSAPR). On August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety and directed the EPA to administer the Clean Air Interstate Rule pending the EPA's development of a valid replacement. On October 5, 2012, the EPA filed for review of the decision by the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter depends on the outcome of any legal challenges and further action by the EPA and cannot be determined at this time.
On August 29, 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized, the revisions would apply the NSPS to all new, reconstructed, and modified CTs, including CTs at combined cycle units, during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and 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 Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.
On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA's actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.
Income Tax Matters
Bonus Depreciation
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Southern Power through 2013. Consequently, Southern Power's positive cash flow benefit is estimated to be between $180 million and $210 million in 2012.
Acquisitions
Apex Nevada Solar, LLC Acquisition
On June 29, 2012, Southern Power and TRE, through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex from Sun Edison, LLC, the original developer of the project. Apex constructed and owns a 20-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility began commercial operation on July 21, 2012. The output of the plant is contracted under a 25-year PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in July 2012. See Note (I) to the Condensed Financial Statements herein for additional information.
Spectrum Nevada Solar, LLC Acquisition
On September 28, 2012, Southern Power and TRE, through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Spectrum from Sun Edison, LLC, the original developer of the project. Spectrum is constructing a 30-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility is expected to begin commercial operation in April 2013. The output of the plant is contracted under a 25-year PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that will begin in 2013. See Note (I) to the Condensed Financial Statements herein for additional information.

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Granville Solar, LLC Acquisition
On October 16, 2012, Southern Power and TRE, through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Granville from Sun Edison, LLC, the original developer of the project. Granville constructed and owns a 2.5-MW solar photovoltaic facility in Oxford, North Carolina. Commercial operation of the solar facility was declared by Granville on October 28, 2012. The output of the plant is contracted under a 20-year PPA with Progress Energy Carolinas that began in October 2012. See Note (I) to the Condensed Financial Statements herein for additional information.
Construction Projects
Cleveland County Units 1-4
In 2008, Southern Power announced plans to build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to begin commercial operation in December 2012. Construction costs incurred through September 30, 2012 were $311.9 million. The total estimated cost of the project is expected to be between $330 million and $345 million.
Nacogdoches Biomass Plant
In 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches from American Renewables LLC, the original developer of the project. Nacogdoches constructed a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant is fueled from wood waste. The plant began commercial operation on June 22, 2012. Project costs incurred through September 30, 2012 were $459.4 million. The final cost of the project is expected to be between $460 million and $465 million.
Power Sales Agreements
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.
In June 2011, Southern Power entered into three PPAs with Georgia Power subject to Georgia PSC and FERC approval. These PPAs were approved by the Georgia PSC on March 20, 2012 and are still subject to approval by the FERC. The ultimate outcome of this matter cannot be determined at this time.
On June 29, 2012, a subsidiary of Southern Power assumed the PPA with Nevada Power Company in connection with the acquisition of Apex. Commercial operation began on July 21, 2012.
On September 7, 2012, Southern Power entered into two PPAs with Jackson Electric Membership Corporation and Greystone Power Corporation to sell 65 MWs and 40 MWs, respectively, from January 2016 through December 2035 from Plant Franklin.
On September 28, 2012, a subsidiary of Southern Power assumed the PPA with Nevada Power Company in connection with the acquisition of Spectrum. The solar facility is expected to begin commercial operation in April 2013.
On October 16, 2012, a subsidiary of Southern Power assumed the PPA with Progress Energy Carolinas in connection with the acquisition of Granville. Commercial operation was declared by Granville on October 28, 2012.

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

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 increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Power and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, 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.
See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies and other matters being litigated which may affect future earnings potential.
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, Contingent Obligations, Depreciation, and Convertible Investment Tax Credits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at September 30, 2012. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
Net cash provided from operating activities totaled $446.3 million for the first nine months of 2012, an increase of $118.1 million as compared to the first nine months of 2011. The increase in cash provided from operating activities was primarily due to an increase in deferred income taxes, partially offset by a decrease in cash received for ITCs. Net cash used for investing activities totaled $281.3 million for the first nine months of 2012 primarily due to the Apex and Spectrum acquisitions, gross property additions related to construction activities at Cleveland County, and payments pursuant to long-term service agreements. Net cash used for financing activities totaled $165.9 million for the first nine months of 2012 primarily due to payment of common stock dividends and a decrease in notes payable in 2012. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities. 

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

Significant asset changes in the balance sheet for the first nine months of 2012 include: a $13.7 million increase in customer accounts receivable from non-affiliated companies and an $11.9 million increase in accounts receivable from affiliated companies primarily due to the seasonality in PPAs; a $37.6 million increase in prepaid service agreements–current due to the timing of plant outages; and a $122.4 million increase in total property, plant, and equipment primarily due to the acquisitions of Apex and Spectrum.
Significant liability and stockholder's equity changes in the balance sheet for the first nine months of 2012 include a $149.1 million increase in accumulated deferred income taxes primarily due to bonus depreciation.
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, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. There are no requirements through September 30, 2013 to fund maturities of long-term debt.
The construction program is subject to periodic review and revision; these amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.
Sources of Capital
Southern Power may use operating cash flows, external funds, or equity capital or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities frequently exceed current assets due to the use of short-term debt as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at September 30, 2012 cash and cash equivalents of approximately $16.1 million and a committed credit facility of $500 million (Facility) expiring in 2016. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power is currently in compliance with all such covenants. Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. 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.
Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.

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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, 2012
 
Short-term Debt During the Period (a)
 
 
Amount
Outstanding
 
Weighted
Average
Interest Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
 
(in millions)
 
 
 
(in millions)
 
 
 
(in millions)
Commercial paper
 
$
101

 
0.5
%
 
$
240

 
0.5
%
 
$
309

(a)
Average and maximum amounts are based upon daily balances during the three month period ended September 30, 2012.
In addition, $0.9 million in anticipated prepayment of notes payable to TRE has been reclassified as short-term debt.
Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and cash.
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 Baa2, or 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, 2012 were as follows:
 
Credit Ratings
Maximum Potential
Collateral Requirements
 
(in millions)
At BBB and Baa2
$
9

At BBB- and/or Baa3
478

Below BBB- and/or Baa3
1,229

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant 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, any credit rating downgrade could impact Southern Power's ability to access capital markets, particularly the short-term debt market.
In addition, through the acquisition of Plant Rowan, Southern Power assumed a PPA with North Carolina Municipal Power Agency No. 1 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, if any, resulting from a credit downgrade.
Market Price Risk
Southern Power is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power's policies in areas such as counterparty exposure and risk management practices. Southern Power'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 tests, and sensitivity analysis.

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

Southern Power's market risk exposure relative to interest rate changes for the third quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness bears interest at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Because energy from Southern Power's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.
The changes in fair value of energy-related derivative contracts for the three and nine months ended September 30, 2012 were as follows:
 
 
Third Quarter
2012
Changes
 
Year-to-Date
2012
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(5.7
)
 
$
(9.2
)
Contracts realized or settled
 
4.9

 
14.1

Current period changes(a)
 
0.7

 
(5.0
)
Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(0.1
)
 
$
(0.1
)
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The changes in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2012 were an increase of $5.6 million and $9.1 million, respectively, which are due to both power and natural gas positions. The changes are attributable to both the volume and prices of power and natural gas as follows:
 
 
September 30,
2012
 
June 30,
2012
 
December 31,
2011
Power – net purchased or (sold)
 
 
 
 
 
 
MWHs (in millions)
 
(0.1
)
 
—

 
0.1

Weighted average contract cost per MWH above (below) market prices (in dollars)
 
$
1.03

 
$
—

 
$
(1.04
)
Natural gas net purchased
 
 
 
 
 
 
Commodity – million mmBtu
 
9.1

 
18.3

 
8.3

Commodity – weighted average contract cost per mmBtu above (below) market prices (in dollars)
 
$
0.02

 
$
0.83

 
$
1.18

The fair value of energy-related derivative contracts by hedge designation reflected in the financial statements as assets (liabilities) consists of the following:
Asset (Liability) Derivatives
 
September 30,
2012
 
December 31,
2011

 
(in millions)
Cash flow hedges
 
$
(0.6
)
 
$
(0.8
)
Not designated
 
0.5

 
(8.4
)
Total fair value
 
$
(0.1
)
 
$
(9.2
)

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

Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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.
Total net unrealized pre-tax gains (losses) recognized in the statements of income for the three and nine months ended September 30, 2012 for energy-related derivative contracts that were not hedges were $5.1 million and $9.0 million, respectively, and will continue to be marked to market until the settlement date. These gains, which are associated with hedging fuel price risk of certain PPA customers, have no impact on net income, as the amounts are credited back to the customers. For the three and nine months ended September 30, 2011, the total net unrealized pre-tax gains (losses) recognized in the statements of income for energy-related derivative contracts that were not hedges were $(0.6) million and $(1.5) million, respectively. Included in these amounts are amounts reimbursable by third parties of $1.0 million and $1.2 million, respectively.
Southern Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2012 were as follows:
 
 
 
 
September 30, 2012
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(0.1
)
 
(0.5
)
 
0.1

 
0.3

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(0.1
)
 
$
(0.5
)
 
$
0.1

 
$
0.3

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Southern Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Southern Power does not expect the impact of these rules to be material.
For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Power in Item 7 and Note 1 under "Financial Instruments" and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
During the nine months ended September 30, 2012, Southern Power prepaid $0.6 million of long-term debt to TRE.
In June 2012, Southern Power issued a $3.6 million promissory note, due June 15, 2032, to TRE related to the financing of Apex. An additional $0.5 million was issued in September 2012 based on the completion of a project milestone.

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

In September 2012, Southern Power issued a $0.9 million promissory note, due September 30, 2032, to TRE related to the financing of Spectrum.
Subsequent to September 30, 2012, Southern Power issued a $0.5 million promissory note, due October 31, 2032, to TRE related to the financing of Granville.
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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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
INDEX TO APPLICABLE NOTES TO
FINANCIAL STATEMENTS BY REGISTRANT
Registrant
Applicable Notes
 
 
Southern Company
A, B, C, D, E, F, G, H, J
 
 
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, E, G, H, I

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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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
 
(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, 2011 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, 2012 and 2011. 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. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation.
Investments in Leveraged Leases
See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information.
The recent financial and operational performance of one of Southern Company's lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the assets. Current projections indicate significant uncertainty as to whether the lessee will be able to pay the December 2012 semi-annual rent payment in full. Southern Company continues to be engaged in discussions with the lessee and the holders of the project's nonrecourse debt to restructure the debt payments and the related rental payments to allow additional capital investment in the project to be made to improve the operation of the generation assets and the financial viability of the lease transaction. Southern Company continues to believe there is a reasonable possibility that it will be able to reach an agreement with the lessee and the debtholders to restructure the project prior to the end of 2012. However, due to continued poor performance of the generation assets and the uncertainties surrounding the receipt of the December 2012 semi-annual rent payment and its ability to successfully restructure the project, Southern Company has placed the lease on nonaccrual status whereby, effective July 2012, income associated with this investment is not recognized in the financial statements. If the attempts at restructuring the project are unsuccessful and the project is ultimately abandoned, the potential impairment loss that would be incurred is approximately $90 million on an after-tax basis. If the restructuring is successfully completed prior to the end of 2012, Southern Company will be required to record a reduction in leveraged lease income of up to approximately $20 million in the fourth quarter 2012. The ultimate outcome of this matter cannot be determined at this time.

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(B)
CONTINGENCIES AND REGULATORY MATTERS
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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 increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. 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 or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, 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.
Insurance Recovery
Mirant Corporation (Mirant) was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and other countries. Mirant was a wholly-owned subsidiary of Southern Company until its initial public offering in 2000. In 2001, Southern Company completed a spin-off to its stockholders of its remaining ownership, and Mirant became an independent corporate entity.
In 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In 2005, Mirant, as a debtor in possession, and the unsecured creditors' committee filed a complaint against Southern Company. Later in 2005, this complaint was transferred to MC Asset Recovery, LLC (MC Asset Recovery) as part of Mirant's plan of reorganization. In 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve this action. The settlement included an agreement where Southern Company paid MC Asset Recovery $202 million. Southern Company filed an insurance claim in 2009 to recover a portion of this settlement and received a nontaxable $25 million payment from its insurance provider on June 14, 2012. Additionally, legal fees related to this insurance settlement totaled approximately $6 million. As a result, the net reduction to expense for this insurance settlement was approximately $19 million.
Environmental Matters
New Source Review Actions
In 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The EPA alleged NSR violations at five coal-fired generating facilities operated by Alabama Power, including a unit co-owned by Mississippi Power, and three coal-fired generating facilities operated by Georgia Power, including a unit co-owned by Gulf Power. The civil action sought penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. After Alabama Power was dismissed from the original action, the EPA filed a separate action in 2001 against Alabama Power (including claims related to the unit co-owned by Mississippi Power) in the U.S. District Court for the Northern District of Alabama.

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In 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree, resolving claims relating to the alleged NSR violations at Plant Miller. In September 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims, including one relating to the unit co-owned by Mississippi Power. In March 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power summary judgment on all remaining claims and dismissed the case with prejudice. That judgment is on appeal to the U.S. Court of Appeals for the Eleventh Circuit. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). The U.S. District Court for the Northern District of Alabama has not ruled on the EPA's motion seeking vacatur of the judgment.
Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.
Climate Change Litigation
Kivalina Case
In 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs allege that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants (including Southern Company) acted in concert and are therefore jointly and severally liable for the plaintiffs' damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. In 2009, the U.S. District Court for the Northern District of California granted the defendants' motions to dismiss the case. On September 21, 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. On October 8, 2012, the plaintiffs filed for review of the decision by the U.S. Court of Appeals for the Ninth Circuit. Southern Company believes that these claims are without merit. While Southern Company believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether Southern Company will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.
Hurricane Katrina Case
In 2005, immediately following Hurricane Katrina, a lawsuit was filed in the U.S. District Court for the Southern District of Mississippi by Ned Comer on behalf of Mississippi residents seeking recovery for property damage and personal injuries caused by Hurricane Katrina. In 2006, the plaintiffs amended the complaint to include Southern Company and many other electric utilities, oil companies, chemical companies, and coal producers. The plaintiffs allege that the defendants contributed to climate change, which contributed to the intensity of Hurricane Katrina. In 2007, the U.S. District Court for the Southern District of Mississippi dismissed the case. On appeal to the U.S. Court of Appeals for the Fifth Circuit, a three-judge panel reversed the U.S. District Court for the Southern District of Mississippi, holding that the case could proceed, but, on rehearing, the full U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs' appeal, resulting in reinstatement of the decision of the U.S. District Court for the Southern District of Mississippi in favor of the defendants. In May 2011, the plaintiffs filed an amended version of their class action complaint, arguing that the earlier dismissal was on procedural grounds and under Mississippi law

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the plaintiffs have a right to re-file. The amended complaint was also filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, Georgia Power, Gulf Power, and Southern Power. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the plaintiffs' amended complaint. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. Each Southern Company entity named in the lawsuit believes that these claims are without merit. While each Southern Company entity named in the lawsuit believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether any Southern Company entity named in the lawsuit will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.
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 properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.
Georgia Power's environmental remediation liability as of September 30, 2012 was $20 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated.
In 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. In September 2011, the EPA issued a unilateral administrative order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site. Georgia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. As a result, in November 2011, Georgia Power filed a response with the EPA indicating that Georgia Power is not willing to undertake the work set forth in the UAO because Georgia Power has sufficient cause to believe it is not a liable party. In November 2011, the EPA sent Georgia Power a letter stating that the EPA does not consider Georgia Power to be in compliance with the UAO. The EPA also stated that it is considering enforcement options against Georgia Power and other UAO recipients who are not complying with the UAO. The EPA may seek to enforce the UAO in court pursuant to its enforcement authority under CERCLA and may seek recovery of its costs in undertaking the UAO work. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.
In addition to the EPA's action at the Ward Transformer Superfund site, in 2009, Georgia Power, along with many other parties, was sued by several existing PRPs for cost recovery for a removal action that is currently taking place. Georgia Power and numerous other defendants moved for a dismissal of these lawsuits. The court denied the dismissal of the lawsuits in March 2010 but granted Georgia Power's motion regarding the dismissal of the claim pertaining to the plaintiffs' joint and several liability.
The ultimate outcome of the Brunswick CERCLA NPL and Ward Transformer Superfund site matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the regulatory treatment described in Note 1 to the financial statements of Georgia Power under "Environmental Remediation" in Item 8 of the Form 10-K, they are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.

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Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $61 million as of September 30, 2012. 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 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, there was no impact on net income as a result of these estimates.
In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power's transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in June 2011. TCEQ approved the feasibility study on September 17, 2012, but the ultimate remedy to be pursued remains under consideration by the agency. Amounts expensed and accrued related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Nuclear Fuel Disposal Cost Litigation
Alabama Power and Georgia Power have contracts with the U.S., acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract.
In 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004.
In 2008, the government filed an appeal and, in March 2011, the U.S. Court of Appeals for the Federal Circuit issued an order in which it affirmed the damage award to Alabama Power, but remanded the Georgia Power portion of the proceeding back to the U.S. Court of Federal Claims for reconsideration of the damages amount in light of the spent nuclear fuel acceptance rates adopted in a separate proceeding by the U.S. Court of Appeals for the Federal Circuit. In July 2011, the court entered final judgment in favor of Alabama Power and awarded Alabama Power approximately $17 million. In April 2012, the award was credited to cost of service for the benefit of Alabama Power customers.
On April 5, 2012, Georgia Power and the government entered into a stipulation to conclude this litigation, which provided for judgment in favor of Georgia Power and awarded Georgia Power approximately $27 million in damages, based on its ownership interests. On April 5, 2012, the stipulation was approved by the U.S. Court of Federal Claims. The proceeds were received and credited to the Georgia Power accounts where the original costs were charged and were used to reduce rate base, fuel, and cost of service for the benefit of Georgia Power customers.

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In 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim) due to the government's alleged continuing breach of contract. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of September 30, 2012 for the second claim. The final outcome of this matter cannot be determined at this time.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle Units 1 and 2 to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle Units 1 and 2 has begun and is expected to be operational in sufficient time to maintain pool full-core discharge capability. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant.
FERC Matters
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 Mississippi Power's request for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. 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.
On January 20, 2012, Mississippi Power reached a settlement agreement with its wholesale customers, which was executed by all parties on March 9, 2012. The settlement agreement provides that base rates under the cost-based electric tariff will increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. In 2012, the amount of base rate revenues to be received from the agreed upon increase will be approximately $17.0 million. On March 12, 2012, Mississippi Power filed an unopposed motion to place wholesale MRA interim rates into effect pending approval of the settlement agreement between the parties by the FERC. On March 28, 2012, the FERC approved the motion to place interim rates into effect beginning in May 2012. On September 27, 2012, Mississippi Power, with its wholesale customers, filed a final settlement agreement with the FERC. On November 5, 2012, the settlement judge certified the settlement agreement to the FERC with the recommendation that it be approved. A decision by the FERC is expected by the end of 2012. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Alabama Power
Rate CNP
See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters  – Alabama Power – Rate CNP" and "Retail Regulatory Matters – Rate CNP," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power's under recovered Rate CNP balance as of September 30, 2012 was $14 million as compared to $6 million at December 31, 2011. Alabama Power's under recovered Rate CNP Environmental balance as of September 30, 2012 was $12 million as compared to $11 million at December 31, 2011. These under recovered balances at September 30, 2012 are included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.

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Retail Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's fuel cost recovery. Alabama Power's over recovered fuel costs as of September 30, 2012 totaled $1 million as compared to a $31 million under recovered balance at December 31, 2011. The over recovered fuel costs at September 30, 2012 are included in other regulatory liabilities, current and the under recovered fuel costs at December 31, 2011 are included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.
Natural Disaster Cost Recovery
See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters  – Alabama Power – Natural Disaster Reserve" and "Retail Regulatory Matters – Natural Disaster Reserve," respectively, in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At September 30, 2012, the NDR had an accumulated balance of $102 million, which is included in Southern Company's and Alabama Power's Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Southern Company's and Alabama Power's Condensed Statements of Income herein.
Georgia Power
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information on Georgia Power's 2010 ARP.
In accordance with the terms of the 2010 ARP, on November 1, 2012, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective on January 1, 2013:
•
Increase the DSM tariffs by approximately $16 million;
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Increase the traditional base tariffs by approximately $58 million to recover the revenue requirements for Plant McDonough-Atkinson Units 4, 5, and 6 for the period through December 31, 2013, which also reflects a separate settlement agreement associated with the June 30, 2011 quarterly construction monitoring report for Plant McDonough-Atkinson (see Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Other Construction" and "Construction – Other Construction," respectively, in Item 8 of the Form 10-K for additional information); and
•
Increase the MFF tariff, consistent with the adjustments above, as well as those related to the IFR and NCCR tariff adjustments described under "Fuel Cost Recovery" and "Nuclear Construction," respectively, herein.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail 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.
On June 21, 2012, the Georgia PSC approved a 19% decrease in Georgia Power's fuel cost recovery rates, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.

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As of September 30, 2012, Georgia Power's fuel cost over recovery balance totaled $199 million. This balance is slightly below the $200 million required to automatically trigger the Georgia PSC's approved IFR adjustment mechanism. On November 1, 2012, Georgia Power filed a request with the Georgia PSC to reduce fuel cost recovery rates, effective January 1, 2013, using the IFR process. The requested reduction would reduce annual billings by approximately $122 million. In accordance with the IFR process, the Georgia PSC will have 30 days to consider Georgia Power's request. The ultimate outcome of this matter cannot be determined at this time.
The over recovered fuel costs at September 30, 2012 are included in current liabilities and other deferred credits and liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. At December 31, 2011, Georgia Power's under recovered fuel balance totaled $137 million and is included in current assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any 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.
2011 Integrated Resource Plan Update
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – 2011 Integrated Resource Plan Update" and "Retail Regulatory Matters – 2011 Integrated Resource Plan Update," respectively, in Item 8 of the Form 10-K for additional information.
On March 20, 2012, the Georgia PSC approved Georgia Power's request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Power's 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.
Separately, on October 16, 2012, the Georgia PSC approved a 50 MW PPA with a Qualifying Facility for capacity and energy that will commence in 2015 and end in 2035. This PPA is expected to result in contractual obligations of approximately $13 million in 2015, $16 million in 2016, and $376 million in total thereafter.
Advanced Solar Initiative
Georgia Power filed a new solar initiative with the Georgia PSC on September 26, 2012. If approved, Georgia Power may acquire up to 210 MWs of additional solar capacity over a three-year period through long-term contracts. The ultimate outcome of this matter cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Construction – Nuclear," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4.
On February 16, 2012, a group of petitioners who had intervened in the NRC's combined construction and operating licenses (COLs) proceedings for Plant Vogtle Units 3 and 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the NRC's issuance of the COLs. In addition, on February 16, 2012, another group of petitioners filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC's certification of the Westinghouse Design Control Document, as amended (DCD). On April 3, 2012, the U.S. Court of Appeals for the District of Columbia Circuit granted a motion filed by these two groups of petitioners to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the COLs for Plant Vogtle Units 3 and 4 with the U.S. District Court for the District of Columbia. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners' motion to stay the effectiveness of the COLs. Georgia Power has intervened in and intends to vigorously contest these petitions.

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In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related CWIP accounts in rate base. Also in 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related CWIP accounts in rate base during the construction period. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. On August 21, 2012, the Georgia PSC voted to approve Georgia Power's sixth semi-annual construction monitoring report including total costs of $2.0 billion for Plant Vogtle Units 3 and 4 incurred through December 31, 2011. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.
In addition, in December 2010, the Georgia PSC approved Georgia Power's NCCR tariff. The NCCR tariff became effective January 1, 2011 and adjustments are filed with the Georgia PSC on November 1 of each year to become effective on January 1 of the following year. On November 1, 2012, Georgia Power filed to increase the NCCR tariff by approximately $50 million effective January 1, 2013. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2012, approximately $59 million of these 2009 and 2010 costs remained in CWIP.
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 (collectively, Owners) and Westinghouse and Stone & Webster, Inc. (collectively, Contractor) have established both informal and formal dispute resolution procedures in accordance with the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement) in order to resolve issues arising during the course of constructing a project of this magnitude. The Contractor and Georgia Power (on behalf of the Owners) have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to costs associated with design changes to the DCD and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the COLs by the NRC. The Owners and the Contractor have begun negotiations regarding these issues, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Through correspondence sent to the Owners, the Contractor provided its proposed adjustment to the contract price and initiated the formal dispute resolution process. The Contractor's estimated adjustment attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars) with respect to these issues. Georgia Power has not agreed with the amount of these proposed adjustments or that the Owners have responsibility for any costs related to these issues. On November 1, 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Owners are not responsible for the costs related to these issues. Also on November 1, 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia, alleging the Owners are responsible for the costs related to these issues and seeking payment from the Owners of the full amount of these costs. While litigation has commenced, Georgia Power expects negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Georgia Power intends to vigorously defend its positions. If these costs ultimately are imposed upon the Owners, Georgia Power would seek

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an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. In connection with these negotiations, the Owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are expected to arise throughout the construction of Plant Vogtle Units 3 and 4.
In addition, there are processes in place that are designed to assure compliance with the design requirements specified in the DCD and the COLs, including rigorous inspection by Southern Nuclear and the NRC that occurs throughout construction. During a routine inspection in April 2012, the NRC identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the NRC. The design changes were determined to have minimal safety significance and, on October 18, 2012, the NRC approved a license amendment request to clarify that the nuclear island concrete and rebar construction will conform to NRC requirements. Various inspection and other issues are expected to arise from time to time as construction proceeds,which may result in additional license amendments or require other resolution.
There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including legal challenges to the NRC issuance of the COLs and certification of the DCD. Similar additional challenges at the state and federal level are expected as construction proceeds.
The ultimate outcome of these matters cannot be determined at this time.
Other Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Other Construction" and "Construction – Other Construction," respectively, in Item 8 of the Form 10-K for additional information.
Plant McDonough Unit 1 was retired on February 29, 2012. Georgia Power placed Plant McDonough-Atkinson Unit 5 into service on April 26, 2012 and Plant McDonough-Atkinson Unit 6 was placed into service on October 28, 2012.
Gulf Power
Retail Base Rate Case
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 for additional information.
On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSC's decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Power's authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Power's retail base rates and charges of $4 million to be effective in January 2013.
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.
On November 5, 2012, the Florida PSC approved Gulf Power's annual rate clause requests for its fuel, purchased power capacity, conservation, and environmental compliance cost recovery factors for 2013. The net effect of the approved changes is a 1.9% rate increase for residential customers using 1,000 KWHs per month.

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Fuel Cost Recovery
See Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
On June 19, 2012, the Florida PSC approved a decrease in Gulf Power's fuel rates of 7.8%, which will reduce annual billings by approximately $58.8 million effective July 2, 2012.
Over recovered fuel costs at September 30, 2012 totaled $28.5 million compared to $9.9 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein.
Purchased Power Capacity Recovery
See Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Purchased Power Capacity Recovery," respectively, in Item 8 of the Form 10-K for additional information.
At September 30, 2012, the under recovered purchased power capacity costs totaled $3.3 million, which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein. At December 31, 2011, the over recovered purchased power capacity costs totaled $8.0 million, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein.
Environmental Cost Recovery
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
On April 3, 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015. Gulf Power's portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.
Over recovered environmental costs at September 30, 2012 totaled $6.9 million compared to $10.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein.
Energy Conservation Cost Recovery
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.
Under recovered energy conservation costs at September 30, 2012 totaled $0.2 million compared to $3.1 million at December 31, 2011. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.

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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 April 2, 2012, Mississippi Power filed a motion to suspend the 2011 PEP lookback filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing also impact the 2011 PEP lookback filing, making it impractical to determine Mississippi Power's actual retail return on investment for 2011 for purposes of the 2011 PEP lookback filing. An order granting the suspension of the 2011 PEP lookback was signed by the Mississippi PSC on May 8, 2012. While Mississippi Power does not expect the resolution of these unresolved matters to have a material impact on its financial statements, the ultimate outcome of these matters cannot be determined at this time.
System Restoration Rider
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K for additional information.
On February 2, 2012, Mississippi Power submitted its 2012 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2012 SRR rate level remain at zero and Mississippi Power be allowed to accrue approximately $3.7 million to the property damage reserve in 2012. On April 3, 2012, the filing was approved by the Mississippi PSC.
Environmental Compliance Overview Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC.
On February 14, 2012, Mississippi Power submitted its 2012 ECO Plan filing, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct a scrubber on Plant Daniel Units 1 and 2, Mississippi Power revised the 2012 ECO Plan filing to exclude scrubber expenditures from rate base, which resulted in a 0.16% decrease in annual revenues. On June 22, 2012, the 2012 ECO Plan filing, including the proposed rate decrease, was approved by the Mississippi PSC, effective on June 29, 2012.
On April 3, 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan. As of September 30, 2012, total project expenditures were $118.4 million, with Mississippi Power's portion being $59.2 million. The ultimate outcome of this matter cannot be determined at this time.

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Certificated New Plant
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Certificated New Plant" in Item 8 of the Form 10-K and "Integrated Coal Gasification Combined Cycle" herein for additional information.
On May 23, 2012, the Mississippi Public Utilities Staff signed a joint stipulation with Mississippi Power to establish a new rate schedule for Certificated New Plant-A (CNP-A), a proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. An amended and restated stipulation was subsequently executed and filed on June 1, 2012. On June 14, 2012, Mississippi Power submitted to the Mississippi PSC a proposed supplemental compliance filing to establish the new CNP-A rate schedule and a stipulated rate increase based upon the revenue request of between $55.3 million and $58.6 million to recover financing costs over the remainder of 2012.
On June 22, 2012, the Mississippi PSC denied the proposed CNP-A rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSC's issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSC's June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Power's request for interim rates under bond while the Mississippi Supreme Court decides Mississippi Power's appeal of the Mississippi PSC's June 22, 2012 decision.
On September 13, 2012, the Mississippi PSC filed the record in the appeal of the Mississippi PSC's June 22, 2012 decision with the Mississippi Supreme Court. If the Mississippi Supreme Court does not render a decision within 180 days of the filing of the record, the rates proposed on June 14, 2012 will go into effect, subject to refund by Mississippi Power.
The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's fuel cost recovery.
At September 30, 2012, the amount of over recovered retail fuel costs included in Mississippi Power's Condensed Balance Sheets herein was $52.8 million compared to $42.4 million at December 31, 2011. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At September 30, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Power's Condensed Balance Sheets herein was $16.8 million and $2.1 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at September 30, 2012, the amount of under recovered MRA emissions allowance cost included in Mississippi Power's Condensed Balance Sheets herein was $0.2 million. At December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power's Condensed Balance Sheets herein was $1.7 million. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, any changes in the billing factors will not have a significant effect on Mississippi Power's revenues or net income, but will affect annual cash flow.

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Storm Damage Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Storm Damage Cost Recovery" in Item 8 in the Form 10-K for information regarding Mississippi Power's storm damage cost recovery. In August 2012, Hurricane Isaac hit the Gulf Coast of the United States and caused damage within Mississippi Power's service area. The estimated total storm restoration costs relating to Hurricane Isaac through September 30, 2012 were $9.7 million. Mississippi Power maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and generally the cost of uninsured damage to its generation facilities and other property. At September 30, 2012, the balance in the storm reserve was $58.7 million.
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.
In May 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the Mississippi PSC order confirming Mississippi Power's application for a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. In June 2010, the Mississippi PSC issued the CPCN (2010 MPSC Order).
In June 2010, the Sierra Club filed an appeal of the Mississippi PSC's June 2010 decision to grant the CPCN for the Kemper IGCC with the Chancery Court. Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club's direct appeal. In February 2011, the Chancery Court issued a judgment affirming the 2010 MPSC Order and, in March 2011, the Sierra Club appealed the Chancery Court's decision to the Mississippi Supreme Court. On March 15, 2012, the Mississippi Supreme Court reversed the Chancery Court's decision and the 2010 MPSC Order and remanded the matter to the Mississippi PSC to correct the 2010 MPSC Order. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN.
On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC. On April 24, 2012, the Mississippi PSC issued a detailed order on remand (2012 MPSC Order) confirming the CPCN for the Kemper IGCC subject to the same conditions set forth in the 2010 MPSC Order. On April 26, 2012, the Sierra Club filed a motion for stay and a notice of appeal of the 2012 MPSC Order with the Chancery Court. On May 18, 2012, Mississippi Power's motion to join the appeal was approved. On August 7, 2012, the Sierra Club withdrew its motion for stay.
The certificated cost estimate of the Kemper IGCC is $2.4 billion, net of $245.3 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2) and excluding the cost of the lignite mine and equipment and the carbon dioxide (CO2) pipeline facilities. The 2012 MPSC Order, like the 2010 MPSC Order, (1) approved a construction cost cap of up to $2.88 billion (exemptions from the cost cap include the cost of the lignite mine and equipment, the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital, which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on the ratepayers, relative to the original proposal), (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's proposal, and (3) approved financing cost recovery on CWIP balances not to exceed the certificated cost estimate, which provided for the accrual of AFUDC in 2010 and 2011 and provides for the current recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the Kemper IGCC).

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Mississippi Power's current cost estimate for the Kemper IGCC equals the $2.88 billion cost cap, including a $40 million to $50 million contingency. The Mississippi PSC and the Mississippi Public Utilities Staff have engaged their independent monitors to assess the current cost estimates and schedule projections for the Kemper IGCC. These consultants are issuing reports with their own opinions as to the likelihood that costs for the Kemper IGCC will remain under the $2.88 billion cost cap and as to the expected in-service date. While Mississippi Power continues to believe its cost estimate and schedule projection remain appropriate based on the current status of the project, it is possible that Mississippi Power will experience further cost increases and/or schedule delays with respect to the Kemper IGCC. Certain factors have caused and may continue to cause the costs for the Kemper IGCC to increase and/or schedule delays to occur including, but not limited to, costs and productivity of labor, adverse weather conditions, shortages and inconsistent quality of equipment, materials and labor, contractor or supplier delay or non-performance under construction or other agreements, and unforeseen engineering problems. To the extent that costs beyond any permitted exceptions to the cost cap exceed $2.88 billion or the Mississippi PSC disallows a portion of the costs relating to the Kemper IGCC, including financing costs, charges to expense may occur and these charges could be material.
The Kemper IGCC, expected to be in service in May 2014, will use locally mined lignite (an abundant, lower heating value coal) from a mine adjacent to the Kemper IGCC as fuel. The mine is scheduled to be placed into service in June 2013. In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County. The estimated capital cost of the mine is approximately $245 million, of which $127 million has been incurred through September 30, 2012.
In May 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a wholly-owned subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. Because Liberty Fuels conducts all of its activities on behalf of Mississippi Power, Liberty Fuels qualifies as a variable interest entity for which Mississippi Power is the primary beneficiary. The contract with Liberty Fuels is effective 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. Consistent with the requirements of consolidation accounting, Liberty Fuels is consolidated in the financial statements of Mississippi Power and accordingly the asset retirement cost and the ARO have been recorded in Mississippi Power's financial statements. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.
In December 2011, the Mississippi Department of Environmental Quality (MDEQ) approved the surface coal mining and the water pollution control permits for the mining operations operated by Liberty Fuels. On January 12, 2012, two individuals each filed a notice of appeal and a request for evidentiary hearing with the MDEQ regarding the surface coal mining and water pollution control permits. On March 8, 2012, the MDEQ permit board affirmed its issuance of the surface coal mining and water pollution control permits.
In 2009, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $133 million of Internal Revenue Code Section 48A tax credits (Phase I) to Mississippi Power. In April 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the rules for Section 48A investment tax credits. Through September 30, 2012, Mississippi Power received or accrued tax benefits totaling $276.8 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. On October 15, 2012, Mississippi Power filed an application with the DOE for certification of the Kemper IGCC for additional tax credits under the Internal Revenue Code Section 48A (Phase III). A portion of the tax credits realized by Mississippi Power may be subject to recapture upon successful completion of SMEPA's

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purchase of undivided interest in the Kemper IGCC. Based on current tax laws and regulations in effect, Mississippi Power expects to receive substantially all of the tax credits accrued through September 30, 2012 by September 30, 2013.
In July 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In December 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval of SMEPA's 17.5% undivided interest in the Kemper IGCC. On February 28, 2012, the Mississippi PSC approved the joint petition for the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. On June 29, 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012 and reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC, subject to approval by the Mississippi PSC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. On September 27, 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.
On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposit has been presented as a current liability in Mississippi Power's Condensed Balance Sheet herein and as financing proceeds in Mississippi Power's Condensed Statement of Cash Flows herein.
As of September 30, 2012, Mississippi Power had spent a total of $2.1 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO2 pipeline facilities, and regulatory filing costs. Of this total, $2.0 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $30.2 million was recorded in other regulatory assets, $3.0 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.
The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. Of the total costs of $51 million incurred through March 2009, $46 million has been reviewed and deemed prudent by the Mississippi PSC in the 2010 MPSC Order and again in the 2012 MPSC Order. A decision regarding the remaining $5 million has not been issued. The timing of the review of the remaining Kemper IGCC costs has not been determined.
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Certificated New Plant" in Item 8 of the Form 10-K and "Retail Regulatory Matters – Certificated New Plant" herein for information on the proposed rate schedules related to the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.


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(C)
FAIR VALUE MEASUREMENTS
As of September 30, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
 
 
 
Fair Value Measurements Using
 
 
As of September 30, 2012:
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
 
 
(in millions)
Southern Company
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
48

 
$
—

 
$
48

Interest rate derivatives
 
—

 
13

 
—

 
13

Nuclear decommissioning trusts(a)
 
476

 
804

 
—

 
1,280

Cash equivalents
 
909

 
—

 
—

 
909

Other investments
 
9

 
—

 
15

 
24

Total
 
$
1,394

 
$
865

 
$
15

 
$
2,274

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
111

 
$
—

 
$
111

Interest rate derivatives
 
—

 
32

 
—

 
32

Total
 
$
—

 
$
143

 
$
—

 
$
143

 
 
 
 
 
 
 
 
 
Alabama Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
11

 
$
—

 
$
11

Nuclear decommissioning trusts:(b)
 
 
 
 
 
 
 
 
Domestic equity
 
289

 
63

 
—

 
352

Foreign equity(d)
 
27

 
52

 
—

 
79

U.S. Treasury and government agency securities
 
—

 
27

 
—

 
27

Corporate bonds
 
—

 
103

 
—

 
103

Mortgage and asset backed securities
 
—

 
26

 
—

 
26

Other
 
—

 
9

 
—

 
9

Cash equivalents
 
235

 
—

 
—

 
235

Total
 
$
551

 
$
291

 
$
—

 
$
842

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
19

 
$
—

 
$
19

Interest rate derivatives
 
—

 
32

 
—

 
32

Total
 
$
—

 
$
51

 
$
—

 
$
51


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Fair Value Measurements Using
 
 
As of September 30, 2012:
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
 
 
(in millions)
Georgia Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
19

 
$
—

 
$
19

Nuclear decommissioning trusts:(b) (c)
 
 
 
 
 
 
 
 
Domestic equity
 
160

 
1

 
—

 
161

Foreign equity(d)
 
—

 
110

 
—

 
110

U.S. Treasury and government agency securities
 
—

 
69

 
—

 
69

Municipal bonds
 
—

 
93

 
—

 
93

Corporate bonds
 
—

 
128

 
—

 
128

Mortgage and asset backed securities
 
—

 
110

 
—

 
110

Other
 
—

 
13

 
—

 
13

Cash equivalents
 
288

 
—

 
—

 
288

Total
 
$
448

 
$
543

 
$
—

 
$
991

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
46

 
$
—

 
$
46

 
 
 
 
 
 
 
 
 
Gulf Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
11

 
$
—

 
$
11

Cash equivalents
 
15

 
—

 
—

 
15

Total
 
$
15

 
$
11

 
$
—

 
$
26

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
24

 
$
—

 
$
24

 
 
 
 
 
 
 
 
 
Mississippi Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
5

 
$
—

 
$
5

Cash equivalents
 
192

 
—

 
—

 
192

Total
 
$
192

 
$
5

 
$
—

 
$
197

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
20

 
$
—

 
$
20

 
 
 
 
 
 
 
 
 
Southern Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
2

 
$
—

 
$
2

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
2

 
$
—

 
$
2

 
(a)
For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.
(b)
Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
(c)
Includes the investment securities pledged to creditors and cash collateral received and payables related to the securities lending program. As of September 30, 2012, approximately $54 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.
(d)
Level 1 securities consist of actively traded stocks, while Level 2 securities consist of pooled funds.

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Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.
"Other investments" include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.
For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics.
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, 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' judgment are also obtained when available.

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As of September 30, 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
As of September 30, 2012:
 
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
 
 
     (in millions)
 
 
 
 
Southern Company
 
 
 
 
 
 
Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
Corporate bonds - commingled funds
 
$
7

 
None
 
Daily
 
1 to 3 days
Other - commingled funds
 
65

 
None
 
Daily/Monthly
 
Daily/7 days
Trust-owned life insurance
 
94

 
None
 
Daily
 
15 days
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
909

 
None
 
Daily
 
Not applicable
Alabama Power
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
Other - commingled funds
 
52

 
None
 
Daily/Monthly
 
Daily/7 days
Trust-owned life insurance
 
94

 
None
 
Daily
 
15 days
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
235

 
None
 
Daily
 
Not applicable
Georgia Power
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
Corporate bonds - commingled funds
 
7

 
None
 
Daily
 
1 to 3 days
Other - commingled funds
 
13

 
None
 
Daily
 
Not applicable
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
288

 
None
 
Daily
 
Not applicable
Gulf Power
 
 
 
 
 
 
 
 
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
15

 
None
 
Daily
 
Not applicable
Mississippi Power
 
 
 
 
 
 
 
 
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
192

 
None
 
Daily
 
Not applicable
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The corporate bonds - commingled funds represent the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

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Alabama Power's nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and nine months ended September 30, 2012, the change in fair value of the funds, which includes reinvested interest and dividends and excludes the Funds' expenses, is recorded as a regulatory liability and was an increase of $53 million and $116 million, respectively, for Southern Company, an increase of $27 million and $60 million, respectively, for Alabama Power, and an increase of $26 million and $56 million, respectively, for Georgia Power.
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.
At September 30, 2012, 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:
 
 
 
 
Southern Company
 
$
21,310

 
$
23,517

Alabama Power
 
$
6,130

 
$
6,955

Georgia Power
 
$
9,524

 
$
10,408

Gulf Power
 
$
1,246

 
$
1,382

Mississippi Power
 
$
1,767

 
$
1,890

Southern Power
 
$
1,307

 
$
1,485

The fair values are primarily Level 2 and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.

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(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 effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
 
 
Three Months
Ended
September 30, 2012
 
Three Months
Ended
September 30, 2011
 
Nine Months
Ended
September 30, 2012
 
Nine Months
Ended
September 30, 2011
 
 
(in millions)
As reported shares
 
876

 
860

 
872

 
854

Effect of options and performance share award units
 
7

 
8

 
8

 
7

Diluted shares
 
883

 
868

 
880

 
861

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 both the three months and nine months ended September 30, 2012 and 2011.
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
 
 
 
 
 
(in thousands)
 
 
 
(in millions)
 
 
Balance at December 31, 2011
 
865,664

 
(539
)
 
$
17,578

 
$
707

 
$
18,285

Net income after dividends on preferred and preference stock
 
—

 
—

 
1,967

 
—

 
1,967

Other comprehensive income (loss)
 
—

 
—

 
(1
)
 
—

 
(1
)
Stock issued
 
11,586

 
—

 
479

 
—

 
479

Stock repurchased, at cost
 
—

 
(2,567
)
 
(117
)
 
—

 
(117
)
Cash dividends on common stock
 
—

 
—

 
(1,267
)
 
—

 
(1,267
)
Other
 
—

 
(38
)
 
—

 
—

 
—

Balance at September 30, 2012
 
877,250

 
(3,144
)
 
$
18,639

 
$
707

 
$
19,346

 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2010
 
843,814

 
(474
)
 
$
16,202

 
$
707

 
$
16,909

Net income after dividends on preferred and preference stock
 
—

 
—

 
1,942

 
—

 
1,942

Other comprehensive income (loss)
 
—

 
—

 
(11
)
 
—

 
(11
)
Stock issued
 
18,634

 
—

 
692

 
—

 
692

Cash dividends on common stock
 
—

 
—

 
(1,193
)
 
—

 
(1,193
)
Other
 
—

 
(45
)
 
1

 
—

 
1

Balance at September 30, 2011
 
862,448

 
(519
)
 
$
17,633

 
$
707

 
$
18,340


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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

In July 2012, Southern Company announced a program to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. Under this program, approximately 2.6 million shares have been repurchased through September 30, 2012 at a total cost of $117 million. Pursuant to Board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, in accordance with applicable securities laws.

(E)
FINANCING
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.

The following table outlines the credit arrangements by company as of September 30, 2012, including expiration dates:
 
 
 
Expires
 
 
 
Executable Term
Loans
 
Due Within  One
Year(a)
Company
 
2012
 
2013
 
2014
and
Beyond(b)

 
Total
 
Unused
 
One
Year

 
Two
Years

 
Term
Out

 
No Term
Out

 
 
(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
Southern Company
 
$
—

 
$
—

 
$
1,000

 
$
1,000

 
$
1,000

 
$
—

 
$
—

 
$
—

 
$
—

Alabama Power
 
—

 
157

 
1,150

 
1,307

 
1,307

 
55

 
—

 
55

 
102

Georgia Power
 
—

 
—

 
1,750

 
1,750

 
1,740

 
—

 
—

 
—

 
—

Gulf Power
 
20

 
60

 
195

 
275

 
275

 
45

 
—

 
45

 
35

Mississippi Power
 
16

 
120

 
165

 
301

 
301

 
25

 
41

 
66

 
70

Southern Power
 
—

 
—

 
500

 
500

 
500

 
—

 
—

 
—

 
—

Other
 
—

 
50

 
—

 
50

 
50

 
25

 
—

 
25

 
25

Total
 
$
36

 
$
387

 
$
4,760

 
$
5,183

 
$
5,173

 
$
150

 
$
41

 
$
191

 
$
232

 
(a)
Reflects facilities expiring on or before September 30, 2013.
(b)
All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


(F)
RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2012. 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 operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.
Components of the net periodic benefit costs for the three and nine months ended September 30, 2012 and 2011 were as follows:
 
Pension Plans
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
  Mississippi  
Power
 
 
(in millions)
Three Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
49

 
$
11

 
$
15

 
$
2

 
$
2

Interest cost
 
98

 
23

 
35

 
5

 
5

Expected return on plan assets
 
(145
)
 
(40
)
 
(56
)
 
(7
)
 
(6
)
Net amortization
 
32

 
8

 
12

 
1

 
2

Net cost
 
$
34

 
$
2

 
$
6

 
$
1

 
$
3

Nine Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
148

 
$
33

 
$
45

 
$
7

 
$
7

Interest cost
 
295

 
70

 
106

 
13

 
14

Expected return on plan assets
 
(436
)
 
(121
)
 
(166
)
 
(20
)
 
(18
)
Net amortization
 
94

 
23

 
34

 
4

 
4

Net cost
 
$
101

 
$
5

 
$
19

 
$
4

 
$
7

Three Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
46

 
$
11

 
$
14

 
$
2

 
$
3

Interest cost
 
97

 
24

 
36

 
4

 
4

Expected return on plan assets
 
(152
)
 
(44
)
 
(59
)
 
(6
)
 
(7
)
Net amortization
 
14

 
3

 
5

 
—

 
1

Net cost (income)
 
$
5

 
$
(6
)
 
$
(4
)
 
$
—

 
$
1

Nine Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
138

 
$
32

 
$
43

 
$
6

 
$
7

Interest cost
 
292

 
72

 
108

 
13

 
13

Expected return on plan assets
 
(456
)
 
(130
)
 
(176
)
 
(20
)
 
(19
)
Net amortization
 
40

 
10

 
14

 
1

 
2

Net cost (income)
 
$
14

 
$
(16
)
 
$
(11
)
 
$
—

 
$
3


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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


Postretirement Benefits
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
 
(in millions)
Three Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
5

 
$
1

 
$
2

 
$
—

 
$
—

Interest cost
 
21

 
6

 
8

 
1

 
1

Expected return on plan assets
 
(15
)
 
(6
)
 
(7
)
 
—

 
—

Net amortization
 
5

 
1

 
3

 
—

 
—

Net cost
 
$
16

 
$
2

 
$
6

 
$
1

 
$
1

Nine Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
16

 
$
4

 
$
5

 
$
1

 
$
1

Interest cost
 
63

 
17

 
27

 
3

 
3

Expected return on plan assets
 
(45
)
 
(18
)
 
(21
)
 
(1
)
 
(1
)
Net amortization
 
15

 
4

 
8

 
—

 
—

Net cost
 
$
49

 
$
7

 
$
19

 
$
3

 
$
3

Three Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
6

 
$
1

 
$
1

 
$
—

 
$
—

Interest cost
 
23

 
6

 
11

 
1

 
1

Expected return on plan assets
 
(16
)
 
(6
)
 
(8
)
 
—

 
—

Net amortization
 
5

 
2

 
3

 
—

 
—

Net cost
 
$
18

 
$
3

 
$
7

 
$
1

 
$
1

Nine Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
16

 
$
4

 
$
5

 
$
1

 
$
1

Interest cost
 
69

 
18

 
31

 
3

 
3

Expected return on plan assets
 
(48
)
 
(19
)
 
(23
)
 
(1
)
 
(1
)
Net amortization
 
15

 
5

 
8

 
—

 
—

Net cost
 
$
52

 
$
8

 
$
21

 
$
3

 
$
3

(G)
EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
Effective Tax Rate
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate.
Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity.
Southern Company's effective tax rate was 35.3% for the nine months ended September 30, 2012 compared to 36.1% for the corresponding period in 2011. The decrease was primarily related to state income tax credits. See "Unrecognized Tax Benefits" herein for additional information.
Alabama Power
Alabama Power's effective tax rate was 38.8% for the nine months ended September 30, 2012 compared to 39.0% for the corresponding period in 2011. The decrease was primarily due to a decrease in Alabama state income taxes as a result of an increase in the state income tax deduction for federal income taxes paid.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Georgia Power
Georgia Power's effective tax rate was 35.8% for the nine months ended September 30, 2012 and for the corresponding period in 2011.
Gulf Power
Gulf Power's effective tax rate was 37.3% for the nine months ended September 30, 2012 compared to 36.6% for the corresponding period in 2011. The increase was primarily due to a decrease in non-taxable AFUDC equity.
Mississippi Power
Mississippi Power's effective tax rate was 26.7% for the nine months ended September 30, 2012 compared to 32.6% for the corresponding period in 2011. The decrease was primarily due to an increase in non-taxable AFUDC equity related to the Kemper IGCC construction.
Southern Power
Southern Power's effective tax rate was 34.4% for the nine months ended September 30, 2012 compared to 35.9% for the corresponding period in 2011. The decrease was primarily due to an increase in convertible investment tax credits and state tax credits.
Unrecognized Tax Benefits
Changes during 2012 for unrecognized tax benefits were as follows:
 
 
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 
 
(in millions)
Unrecognized tax benefits as of December 31, 2011
 
$
120

 
$
32

 
$
47

 
$
3

 
$
5

 
$
3

Tax positions from current periods
 
7

 
3

 
2

 
—

 
—

 
1

Tax positions from prior periods
 
(21
)
 
(4
)
 
(18
)
 
1

 
—

 
(2
)
Reductions due to settlements
 
(5
)
 
(2
)
 
(3
)
 
(1
)
 
—

 
1

Reductions due to expired statute of limitations
 
(3
)
 
—

 
(3
)
 
—

 
—

 
—

Balance as of September 30, 2012
 
$
98

 
$
29

 
$
25

 
$
3

 
$
5

 
$
3

The tax positions from current periods relate primarily to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. The decreases in tax positions from prior periods primarily relate to state income tax credits. The reductions due to settlements relate to a settlement with the IRS of the calculation methodology for the production activities deduction.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The impact on the effective tax rate, if recognized, was as follows:
 
 
 
As of September 30, 2012
 
As of
December 31,
2011
 
 
 
 
Southern Company
 
 
(in millions)
Tax positions impacting the effective tax rate
 
 
 
$
38

 
$
69

Tax positions not impacting the effective tax rate
 
 
 
60

 
51

Balance of unrecognized tax benefits
 
 
 
$
98

 
$
120

The tax positions impacting the effective tax rate primarily relate to state income tax credits and a litigation settlement refund claim for Southern Company. See Note 5 to the financial statements of Southern Company under "Effective Tax Rate" in Item 8 of the Form 10-K for additional information. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was as follows:
 
 
 
 
Southern Company
 
 
(in millions)
Interest accrued as of December 31, 2011
 
 
 
$
10

Interest reclassified due to settlements
 
 
 
(9
)
Interest accrued during the period
 
 
 
—

Balance as of September 30, 2012
 
 
 
$
1

All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with state income tax credits and a settlement with the IRS related to the calculation methodology for the production activities deduction.
None of the registrants accrued any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the registrants' unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the tax accounting method change for repairs-generation assets, as well as the conclusion or settlement of federal and state audits, could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
Tax Method of Accounting for Repairs
Southern Company submitted a tax accounting method change for repair costs associated with its subsidiaries' generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. In August 2011, the IRS issued a revenue procedure, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. However, the IRS continues to work with the utility industry in an effort to resolve the repair costs for generation assets matter in a consistent manner for all utilities. In December 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2012. The utility industry anticipates more detailed guidance concerning these regulations. Due to uncertainty regarding the ultimate resolution of the repair costs for generation assets, an unrecognized tax position has been recorded for the tax accounting method change for repairs-generation assets. The ultimate outcome of this matter cannot be determined at this time.

185
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


(H)
DERIVATIVES
Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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 gross basis.
Energy-Related Derivatives
The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.
To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
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 operating companies' 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 and 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 industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

186
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 30, 2012, 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 date for derivatives not designated as hedges, were as follows:
 
 
 
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
 
 
(in millions)
 
 
 
 
Southern Company
 
270

 
2017
 
2017

Alabama Power
 
55

 
2017
 
—

Georgia Power
 
107

 
2017
 
—

Gulf Power
 
63

 
2017
 
—

Mississippi Power
 
36

 
2017
 
—

Southern Power
 
9

 
2012
 
2017

In addition to the volumes discussed in the above table, the traditional 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 7 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 3 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 1 million mmBtu for Mississippi Power, and 1 million mmBtu for Southern Power.
For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending September 30, 2013 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries 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.
At September 30, 2012, the following interest rate derivatives were outstanding:
 
 
 
Notional
Amount
 
Interest Rate
Received
 
Interest Rate
Paid
 
Hedge
Maturity Date
 
Fair Value
Gain (Loss)
September 30, 2012
 
 
(in millions)
 
 
 
 
 
 
 
(in millions)
Cash flow hedges of forecasted transactions
 
 
 
 
 
 
 
 
Alabama Power
 
$
300

 
3-month
LIBOR

 
2.90
%
(a) 
December 2022
 
$
(32
)
Fair value hedges of existing debt
 
 
 
 
 
 
 
 
 
 
Southern Company
 
350

 
4.15
%
 
3-month
LIBOR  +
1.96%

(a) 
May 2014
 
13

Total
 
$
650

 
 
 
 
 
 
 
$
(19
)
(a)
Weighted average

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending September 30, 2013, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.
 
Registrant
 
Estimated Gain (Loss) to
be Reclassified for the
12 Months Ending
September 30, 2013
 
Total Deferred
Gains (Losses)
Amortized
 Through
 
 
(in millions)
 
 
Southern Company
 
$
(16
)
 
2037
Alabama Power
 
(2
)
 
2035
Georgia Power
 
(3
)
 
2037
Gulf Power
 
(1
)
 
2020
Mississippi Power
 
(1
)
 
2022
Southern Power
 
(9
)
 
2016
Foreign Currency Derivatives
Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge 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. Any ineffectiveness is typically recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
At September 30, 2012, the following foreign currency derivatives were outstanding:
 
 
 
Notional
Amount
 
Forward
Rate
 
Hedge
Maturity
Date
 
Fair Value
Gain (Loss)
September 30, 2012(c)
 
 
(in millions)
 
 
 
 
 
(in millions)
Fair value hedges of firm commitments
 
 
 
 
 
 
 
 
Mississippi Power
 
EUR0.7
 
1.3758 Dollars per Euro
 
March 2014
 
$
—

Derivatives not designated as hedges(b)
 
 
 
 
 
 
 
 
Mississippi Power
 
EUR10.5
 
1.2571 Dollars per Euro
(a) 
N/A
 
—

Total
 
EUR11.2
 
 
 
 
 
$
—

(a)
Weighted average
(b)
Derivatives are not designated as hedges due to the uncertainty of future contract payment dates.
(c)
Amounts are not material at September 30, 2012.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Derivative Financial Statement Presentation and Amounts
At September 30, 2012, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
 
Asset Derivatives at September 30, 2012
 
 
Fair Value
Derivative Category and Balance Sheet Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern  
Power
 
 
(in millions)
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Other current assets
 
$
17

 
$
3

 
$
9

 
$
4

 
$
1

 
 
Other deferred charges and assets
 
29

 
8

 
10

 
7

 
4

 
 
Total derivatives designated as hedging instruments for regulatory purposes
 
$
46

 
$
11

 
$
19

 
$
11

 
$
5

 
N/A

Derivatives designated as hedging instruments in cash flow and fair value hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Other current assets
 
$
6

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Other deferred charges and assets
 
7

 
—

 
—

 
—

 
—

 
—

Total derivatives designated as hedging instruments in cash flow and fair value hedges
 
$
13

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Assets from risk management activities
 
$
1

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1

Other deferred charges and assets
 
1

 
—

 
—

 
—

 
—

 
1

Total derivatives not designated as hedging instruments
 
$
2

 
$
—

 
$
—

 
$
—

 
$
—

 
$
2

Total asset derivatives
 
$
61

 
$
11

 
$
19

 
$
11

 
$
5

 
$
2


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Table of Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Liability Derivatives at September 30, 2012
 
 
Fair Value
Derivative Category and
Balance Sheet Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern  
Power  
 
 
(in millions)
Derivatives designated as hedging instruments for regulatory purposes
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities from risk management activities
 
$
71

 
$
14

 
$
31

 
$
13

 
$
13

 
 
Other deferred credits and liabilities
 
38

 
5

 
15

 
11

 
7

 
 
Total derivatives designated as hedging instruments for regulatory purposes
 
$
109

 
$
19

 
$
46

 
$
24

 
$
20

 
N/A

Derivatives designated as hedging instruments in cash flow and fair value hedges
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities from risk management activities
 
$
1

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1

Interest rate derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities from risk management activities
 
32

 
32

 
—

 
—

 
—

 
—

Total derivatives designated as hedging instruments in cash flow and fair value hedges
 
$
33

 
$
32

 
$
—

 
$
—

 
$
—

 
$
1

Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities from risk management activities
 
$
1

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1

Total liability derivatives
 
$
143

 
$
51

 
$
46

 
$
24

 
$
20

 
$
2

All derivative instruments are measured at fair value. See Note (C) herein for additional information.
At September 30, 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet
Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
 
(in millions)
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
Other regulatory assets, current
 
$
(71
)
 
$
(14
)
 
$
(31
)
 
$
(13
)
 
$
(13
)
Other regulatory assets, deferred
 
(38
)
 
(5
)
 
(15
)
 
(11
)
 
(7
)
Other regulatory liabilities, current
 
17

 
3

 
9

 
4

 
1

Other regulatory liabilities, deferred
 
29

 
8

 
—

 
7

 
4

Other deferred credits and liabilities(a)
 
—

 
—

 
10

 
—

 
—

Total energy-related derivative gains (losses)
 
$
(63
)
 
$
(8
)
 
$
(27
)
 
$
(13
)
 
$
(15
)
(a)
Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.
For the three and nine months ended September 30, 2012 and September 30, 2011, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company's statements of income were immaterial.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


For the three and nine months ended September 30, 2012, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company's and Mississippi Power's statements of income were immaterial. For the three and nine months ended September 30, 2011, the pre-tax losses of foreign currency derivatives designated as fair value hedging instruments on Southern Company's and Mississippi Power's statements of income were $(3) million and $(2) million, respectively. The pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on both Southern Company's and Mississippi Power's statements of income were offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there was no impact on Southern Company's or Mississippi Power's statements of income.
For the three months ended September 30, 2012 and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income 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
 
 
2012
 
2011
 
 
 
2012
 
2011
 
 
(in millions)
 
 
 
(in millions)
Southern Company
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
(4
)
 
$
(27
)
 
Interest expense, net of amounts capitalized
 
$
(4
)
 
$
(5
)
Alabama Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
(4
)
 
$
(12
)
 
Interest expense, net of amounts capitalized
 
$
—

 
$
—

Georgia Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
—

 
$
—

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

 
$
(15
)
 
Interest expense, net of amounts capitalized
 
$
—

 
$
—

Southern Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
—

 
$
—

 
Interest expense, net of amounts capitalized
 
$
(3
)
 
$
(3
)

For the nine months ended September 30, 2012 and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income 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
 
 
2012
 
2011
 
 
 
2012
 
2011
 
 
(in millions)
 
 
 
(in millions)
Southern Company
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
(16
)
 
$
(23
)
 
Interest expense, net of amounts capitalized
 
$
(12
)
 
$
(10
)
Alabama Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
(15
)
 
$
(8
)
 
Interest expense, net of amounts capitalized
 
$
—

 
$
3

Georgia Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
—

 
$
—

 
Interest expense, net of amounts capitalized
 
$
(3
)
 
$
(3
)
Gulf Power
 
 
 
 
 
 
 
 
 
 
  Interest rate derivatives
 
$
—

 
$
—

 
Interest expense, net of amounts capitalized
 
$
(1
)
 
$
(1
)
Mississippi Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
(1
)
 
$
(15
)
 
Interest expense, net of amounts capitalized
 
$
(1
)
 
$
—

Southern Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
—

 
$
—

 
Interest expense, net of amounts capitalized
 
$
(8
)
 
$
(8
)


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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three and nine months ended September 30, 2012 and 2011, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments on the statements of income were immaterial for all registrants.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
For Southern Power's energy-related derivatives not designated as hedging instruments, a substantial portion of the pre-tax realized and unrealized gains and losses is associated with hedging fuel price risk of certain PPA customers and has no impact on net income or on fuel expense as presented in Southern Company's and Southern Power's statements of income. As a result, for the three and nine months ended September 30, 2012 and 2011, the pre-tax effects of energy-related derivatives not designated as hedging instruments on Southern Company's and Southern Power's statements of income were immaterial.
For the three and nine months ended September 30, 2012, the pre-tax effects of foreign currency derivatives not designated as hedging instruments were recorded as regulatory assets and liabilities and were immaterial for Southern Company and Mississippi Power.
Contingent Features
The registrants 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, 2012, the fair value of derivative liabilities with contingent features, by registrant, was as follows: 
 
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 
 
 
 
 
 
(in millions)
 
 
 
 
 
 
Derivative liabilities
 
$
10

 
$
2

 
$
4

 
$
2

 
$
2

 
$
—

At September 30, 2012, the registrants had no collateral posted with their derivative counterparties. 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 under the same master netting arrangement. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $10 million for each registrant. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade.
Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power 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 operating companies, and Southern Power 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 operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)



(I)
ACQUISITIONS
Apex Nevada Solar, LLC Acquisition
On June 29, 2012, Southern Power and Turner Renewable Energy, Inc. (TRE), through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex) from Sun Edison, LLC, the original developer of the project. Apex constructed and owns a 20-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility began commercial operation on July 21, 2012. The output of the plant is contracted under a 25-year PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in July 2012. This PPA is being accounted for as an operating lease. The acquisition is in accordance with Southern Power's overall growth strategy.
Southern Power's acquisition of Apex included cash consideration of $102 million, of which $86.5 million was paid at closing and an additional $9.5 million was paid on September 28, 2012 upon completion of a project milestone. The remaining $6 million is expected to be paid in November 2012 upon achievement of the final milestone. As of September 30, 2012, the allocation of the purchase price to individual assets has not been finalized. As of the acquisition date, the entire purchase price was recorded as CWIP. Revenues and earnings with respect to Apex for the period ended September 30, 2012 were immaterial.
Spectrum Nevada Solar, LLC Acquisition
On September 28, 2012, Southern Power and TRE, through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Spectrum Nevada Solar, LLC (Spectrum) from Sun Edison, LLC, the original developer of the project. Spectrum is constructing a 30-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility is expected to begin commercial operation in April 2013. The output of the plant is contracted under a 25-year PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that will begin in 2013. This PPA will be accounted for as an operating lease. The acquisition is in accordance with Southern Power's overall growth strategy.
Southern Power's acquisition of Spectrum consisted of cash consideration of $17.6 million paid at closing. An additional $99.9 million will be paid to a subsidiary of Sun Edison, LLC to complete the construction of the solar facility. Due to the proximity of the closing date to September 30, 2012, there has not been sufficient time to complete the final allocation of the purchase price to individual assets. As of September 30, 2012, the $17.6 million purchase price was reflected in CWIP on Southern Power's Condensed Balance Sheet herein.
Granville Solar, LLC Acquisition
On October 16, 2012, Southern Power and TRE, through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Granville Solar, LLC (Granville) from Sun Edison, LLC, the original developer of the project. Granville constructed and owns a 2.5-MW solar photovoltaic facility in Oxford, North Carolina. Commercial operation of the solar facility was declared by Granville on October 28, 2012. The output of the plant is contracted under a 20-year PPA with Progress Energy Carolinas that began in October 2012. This PPA is being accounted for as an operating lease. The acquisition is in accordance with Southern Power's overall growth strategy.
Southern Power's acquisition of Granville included cash consideration of $10.4 million, of which $7.8 million was paid at closing. The remaining $2.6 million will be paid upon achievement of certain milestones.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)



(J)
SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $112 million and $330 million for the three and nine months ended September 30, 2012, respectively, and $85 million and $239 million for the three and nine months ended September 30, 2011, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:
 
 
 
Electric Utilities
 
 
 
 
 
 
 
 
Traditional
Operating
Companies
 
Southern
Power
 
Eliminations
 
Total
 
All
Other
 
Eliminations
 
Consolidated
 
 
(in millions)
Three Months Ended September 30, 2012:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
4,794

 
$
355

 
$
(116
)
 
$
5,033

 
$
36

 
$
(20
)
 
$
5,049

Segment net income (loss)(a)
 
908

 
68

 
1

 
977

 
1

 
(2
)
 
976

Nine Months Ended September 30, 2012:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
12,232

 
$
894

 
$
(338
)
 
$
12,788

 
$
109

 
$
(63
)
 
$
12,834

Segment net income (loss)(a)
 
1,797

 
144

 
—

 
1,941

 
30

 
(4
)
 
1,967

Total assets at September 30, 2012
 
$
57,862

 
$
3,782

 
$
(158
)
 
$
61,486

 
$
1,084

 
$
(607
)
 
$
61,963

Three Months Ended September 30, 2011:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
5,145

 
$
363

 
$
(97
)
 
$
5,411

 
$
38

 
$
(21
)
 
$
5,428

Segment net income (loss)(a)
 
862

 
56

 
—

 
918

 
—

 
(2
)
 
916

Nine Months Ended September 30, 2011:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
13,246

 
$
950

 
$
(288
)
 
$
13,908

 
$
114

 
$
(61
)
 
$
13,961

Segment net income (loss)(a)
 
1,805

 
138

 
—

 
1,943

 
2

 
(3
)
 
1,942

Total assets at December 31, 2011
 
$
54,622

 
$
3,581

 
$
(127
)
 
$
58,076

 
$
1,592

 
$
(401
)
 
$
59,267

(a) After dividends on preferred and preference stock of subsidiaries
Products and Services

 
 
Electric Utilities' Revenues
Period
 
Retail
 
Wholesale
 
Other
 
Total
 
 
(in millions)
Three Months Ended September 30, 2012
 
$
4,379

 
$
497

 
$
157

 
$
5,033

Three Months Ended September 30, 2011
 
4,693

 
557

 
161

 
5,411

Nine Months Ended September 30, 2012
 
$
11,068

 
$
1,261

 
$
459

 
$
12,788

Nine Months Ended September 30, 2011
 
11,931

 
1,513

 
464

 
13,908



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Table of Contents


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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(c) Issuer Purchases of Equity Securities

2012
 


Total Number of
Shares
Purchased (a)
 


Average Price
Paid Per Share
 

Total Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
 
Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (a)
July 1 -
July 30
 
N/A

 
N/A

 
N/A

 
N/A
August 1 -
August 30
 
N/A

 
N/A

 
N/A

 
N/A
September 1 -
September 30
 
2,567,254

 
$
45.450

 
2,567,254

 
N/A
Total
 
2,567,254

 
$
45.450

 
2,567,254

 
N/A

(a)
In July 2012, Southern Company announced that it planned to use the proceeds received from stock option exercises during 2012 (including $317 million received through June 30, 2012) and 2013 to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. In September 2012, Southern Company engaged an agent to repurchase shares of Southern Company common stock on an ongoing basis to partially offset the incremental shares issued under its employee and director stock plans. As of September 30, 2012, Southern Company has repurchased a total of 2,567,254 shares under this program.


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Item 6.    Exhibits.
(4) Instruments Describing Rights of Security Holders, Including Indentures
 
 
 
Alabama Power
 
 
 
 
 
(b)1
-
Forty-Ninth Supplemental Indenture to Senior Note Indenture dated as of October 16, 2012, providing for the issuance of the Series 2012B 0.550% Senior Notes due October 15, 2015. (Designated in Form 8-K dated October 9, 2012, File No. 1-3164, as Exhibit 4.2.)
 
 
 
Georgia Power
 
 
 
 
 
(c)1
-
Forty-Eighth Supplemental Indenture to Senior Note Indenture dated as of August 10, 2012, providing for the issuance of the Series 2012C 0.75% Senior Notes due August 10, 2015. (Designated in Form 8-K dated August 10, 2012, File No. 1-6468, as Exhibit 4.2(b).)
 
 
 
(24) Power of Attorney and Resolutions
 
 
 
Southern Company
 
 
 
 
(a)1
-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)
 
 
 
Alabama Power
 
 
 
 
(b)1
-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)
 
 
 
Georgia Power
 
 
 
 
(c)1
-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)
 
 
 
Gulf Power
 
 
 
 
(d)1
-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 001-31737 as Exhibit 24(d) and incorporated herein by reference.)
 
 
 
(d)2
-
Power of Attorney for S. W. Connally, Jr. (Designated in the Form 10-Q for the quarter ended June 30, 2012, File No. 001-31737 as Exhibit 24(d)(2) and incorporated herein by reference.)
 
 
 
Mississippi Power
 
 
 
 
(e)1
-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)
 
 
 
Southern Power
 
 
 
 
(f)1
-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)
 
 
 
(31) Section 302 Certifications
 
 
 
Southern Company
 
 
 
 
(a)1
-
Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
(a)2
-
Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Alabama Power
 
 
 
 
(b)1
-
Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 

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(b)2
-
Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
Georgia Power
 
 
 
 
(c)1
-
Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
(c)2
-
Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
Gulf Power
 
 
 
 
(d)1
-
Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
(d)2
-
Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
Mississippi Power
 
 
 
 
(e)1
-
Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
(e)2
-
Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
Southern Power
 
 
 
 
(f)1
-
Certificate of Southern Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
(f)2
-
Certificate of Southern Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
(32) Section 906 Certifications
 
 
 
Southern Company
 
 
 
 
(a)
-
Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
Alabama Power
 
 
 
 
(b)
-
Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
Georgia Power
 
 
 
 
(c)
-
Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
Gulf Power
 
 
 
 
(d)
-
Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
Mississippi Power
 
 
 
 
(e)
-
Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
Southern Power
 
 
 
 
(f)
-
Certificate of Southern Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

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(101)
 
XBRL — Related Documents
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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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: November 7, 2012

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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
 
Charles D. McCrary
 
 
 
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: November 7, 2012

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GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
 
 
GEORGIA POWER COMPANY
 
 
 
 
By
 
W. Paul Bowers
 
 
President and Chief Executive Officer
 
 
(Principal Executive Officer)
 
 
 
 
By
 
Ronnie R. Labrato
 
 
Executive Vice President, Chief Financial Officer, and Treasurer
 
 
(Principal Financial Officer)
 
 
 
 
By
 
/s/ Melissa K. Caen
 
 
 
(Melissa K. Caen, Attorney-in-fact)
 
Date: November 7, 2012

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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.
 
 
President and Chief Executive Officer
 
 
(Principal Executive Officer)
 
 
 
 
By
 
Richard S. Teel
 
 
Vice President and Chief Financial Officer
 
 
(Principal Financial Officer)
 
 
 
 
By
 
/s/ Melissa K. Caen
 
 
 
(Melissa K. Caen, Attorney-in-fact)
 
Date: November 7, 2012

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MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
 
 
MISSISSIPPI POWER COMPANY
 
 
 
 
By
 
Edward Day, VI
 
 
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: November 7, 2012

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SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
 
 
SOUTHERN POWER COMPANY
 
 
 
 
By
 
Oscar C. Harper IV
 
 
President and Chief Executive Officer
 
 
(Principal Executive Officer)
 
 
 
 
By
 
Michael W. Southern
 
 
Senior Vice President, Chief Financial Officer, and Treasurer
 
 
(Principal Financial Officer)
 
 
 
 
By
 
/s/ Melissa K. Caen
 
 
 
(Melissa K. Caen, Attorney-in-fact)
 
Date: November 7, 2012

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