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GEORGIA POWER CO - Quarter Report: 2013 March (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 March 31, 2013
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 March 31, 2013

The Southern Company
 
Par Value $5 Per Share
 
870,390,537

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
 
4,942,717

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.

2
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INDEX TO QUARTERLY REPORT ON FORM 10-Q
March 31, 2013


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


3
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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
Georgia Power's 2011 Integrated Resource Plan update filed with the Georgia PSC
2013 IRP
Georgia Power's triennial Integrated Resource Plan filed with the Georgia PSC on January 31, 2013
AFUDC
Allowance for Funds Used During Construction
Alabama Power
Alabama Power Company
AOCI
Accumulated Other Comprehensive Income
Baseload Act
State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
Clean Air Act
Clean Air Act Amendments of 1990
Contractor
Westinghouse and Stone & Webster, Inc.
CPCN
Certificate of Public Convenience and Necessity
CWIP
Construction Work in Progress
DOE
U.S. Department of Energy
ECO Plan
Mississippi Power's Environmental Compliance Overview Plan
EPA
U.S. Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
Form 10-K
Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power for the year ended December 31, 2012
Form 10-K/A
Annual Report on Form 10-K of Mississippi Power for the year ended December 31, 2012, as amended by Amendment No. 1
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
MATS rule
Mercury and Air Toxics Standards Rule
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

4
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Owners
Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
PEP
Mississippi Power's Performance Evaluation Plan
Plant Vogtle Units 3 and 4
Two new nuclear generating units under construction at Plant Vogtle
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
PSC
Public Service Commission
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


5
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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, postretirement benefit plan, and nuclear decommissioning trust fund contributions, financing activities, start and completion dates of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the American Taxpayer Relief Act of 2012, 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, 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 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, including the development and construction of facilities with designs that have not been finalized or previously constructed, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any operational and environmental performance standards, including the requirements of tax credits and other incentives;
•
investment performance of Southern Company's employee benefit plans and the Southern Company system's 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 cost recovery for the Kemper IGCC, including Mississippi PSC review of Mississippi Power's proposed rate recovery plan, the prudence review of Kemper IGCC costs and actions relating to proposed securitization; the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA as contemplated by Mississippi Power's proposed rate recovery plan; satisfaction of requirements to utilize investment tax credits and grants; and the outcome of any legal or regulatory proceedings regarding the Mississippi PSC's issuance of the CPCN for the Kemper IGCC, the settlement agreement between Mississippi Power and the Mississippi PSC, or the Baseload Act;

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•
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
•
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;
•
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 (including the Form 10-K and the Form 10-K/A) filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.


7
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THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

8
Table of Contents


THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Operating Revenues:
 
 
 
Retail revenues
$
3,298

 
$
3,092

Wholesale revenues
432

 
349

Other electric revenues
155

 
148

Other revenues
12

 
15

Total operating revenues
3,897

 
3,604

Operating Expenses:
 
 
 
Fuel
1,262

 
1,064

Purchased power
95

 
141

Other operations and maintenance
974

 
967

Depreciation and amortization
466

 
441

Taxes other than income taxes
235

 
225

Estimated loss on Kemper IGCC
540

 
—

Total operating expenses
3,572

 
2,838

Operating Income
325

 
766

Other Income and (Expense):
 
 
 
Allowance for equity funds used during construction
41

 
31

Leveraged lease income (loss)
(21
)
 
6

Interest expense, net of amounts capitalized
(211
)
 
(211
)
Other income (expense), net
(6
)
 
(8
)
Total other income and (expense)
(197
)
 
(182
)
Earnings Before Income Taxes
128

 
584

Income taxes
31

 
200

Consolidated Net Income
97

 
384

Dividends on Preferred and Preference Stock of Subsidiaries
16

 
16

Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries
$
81

 
$
368

Common Stock Data:
 
 
 
Earnings per share (EPS) -
 
 
 
Basic EPS
$
0.09

 
$
0.42

Diluted EPS
$
0.09

 
$
0.42

Average number of shares of common stock outstanding (in millions)
 
 
 
Basic
870

 
868

Diluted
875

 
877

Cash dividends paid per share of common stock
$
0.4900

 
$
0.4725

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 March 31,
 
2013
 
2012
 
(in millions)
Consolidated Net Income
$
97

 
$
384

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

 
3

Reclassification adjustment for amounts included in net income, net of tax of $2 and $1, respectively
3

 
2

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

 
1

Total other comprehensive income (loss)
4

 
6

Dividends on preferred and preference stock of subsidiaries
(16
)
 
(16
)
Comprehensive Income
$
85

 
$
374

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 Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Operating Activities:
 
 
 
Consolidated net income
$
97

 
$
384

Adjustments to reconcile consolidated net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
568

 
529

Deferred income taxes
(92
)
 
104

Allowance for equity funds used during construction
(41
)
 
(31
)
Leveraged lease (income) loss
21

 
(6
)
Pension, postretirement, and other employee benefits
22

 
16

Stock based compensation expense
26

 
25

Estimated loss on Kemper IGCC
540

 
—

Other, net
(62
)
 
8

Changes in certain current assets and liabilities —
 
 
 
-Receivables
29

 
372

-Fossil fuel stock
36

 
(218
)
-Materials and supplies
52

 
4

-Other current assets
(72
)
 
(64
)
-Accounts payable
(47
)
 
(136
)
-Accrued taxes
(98
)
 
(167
)
-Accrued compensation
(282
)
 
(305
)
-Other current liabilities
40

 
53

Net cash provided from operating activities
737

 
568

Investing Activities:
 
 
 
Property additions
(1,197
)
 
(1,231
)
Investment in restricted cash
(78
)
 
1

Nuclear decommissioning trust fund purchases
(262
)
 
(336
)
Nuclear decommissioning trust fund sales
261

 
334

Cost of removal, net of salvage
(30
)
 
(32
)
Change in construction payables, net
6

 
(153
)
Other investing activities
21

 
(10
)
Net cash used for investing activities
(1,279
)
 
(1,427
)
Financing Activities:
 
 
 
Increase in notes payable, net
468

 
174

Proceeds —
 
 
 
Long-term debt issuances
1,035

 
1,400

Interest-bearing refundable deposit related to asset sale
—

 
150

Common stock issuances
42

 
116

Redemptions —
 
 
 
Long-term debt
(656
)
 
(827
)
Common stock repurchased
(18
)
 
—

Payment of common stock dividends
(426
)
 
(410
)
Payment of dividends on preferred and preference stock of subsidiaries
(16
)
 
(16
)
Other financing activities
—

 
1

Net cash provided from financing activities
429

 
588

Net Change in Cash and Cash Equivalents
(113
)
 
(271
)
Cash and Cash Equivalents at Beginning of Period
628

 
1,315

Cash and Cash Equivalents at End of Period
$
515

 
$
1,044

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $17 and $21 capitalized for 2013 and 2012, respectively)
$
187

 
$
178

Income taxes, net
4

 
2

Noncash transactions — accrued property additions at end of period
501

 
420


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 March 31,
2013
 
At December 31,
2012
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
515

 
$
628

Restricted cash and cash equivalents
 
25

 
7

Receivables —
 
 
 
 
Customer accounts receivable
 
1,011

 
961

Unbilled revenues
 
390

 
441

Under recovered regulatory clause revenues
 
26

 
29

Other accounts and notes receivable
 
223

 
235

Accumulated provision for uncollectible accounts
 
(15
)
 
(17
)
Fossil fuel stock, at average cost
 
1,783

 
1,819

Materials and supplies, at average cost
 
940

 
1,000

Vacation pay
 
166

 
165

Prepaid expenses
 
693

 
657

Other regulatory assets, current
 
115

 
163

Other current assets
 
60

 
74

Total current assets
 
5,932

 
6,162

Property, Plant, and Equipment:
 
 
 
 
In service
 
63,586

 
63,251

Less accumulated depreciation
 
22,219

 
21,964

Plant in service, net of depreciation
 
41,367

 
41,287

Other utility plant, net
 
266

 
263

Nuclear fuel, at amortized cost
 
861

 
851

Construction work in progress
 
6,193

 
5,989

Total property, plant, and equipment
 
48,687

 
48,390

Other Property and Investments:
 
 
 
 
Nuclear decommissioning trusts, at fair value
 
1,365

 
1,303

Leveraged leases
 
648

 
670

Miscellaneous property and investments
 
217

 
216

Total other property and investments
 
2,230

 
2,189

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
1,387

 
1,385

Unamortized debt issuance expense
 
144

 
133

Unamortized loss on reacquired debt
 
303

 
309

Other regulatory assets, deferred
 
4,021

 
4,032

Other deferred charges and assets
 
570

 
549

Total deferred charges and other assets
 
6,425

 
6,408

Total Assets
 
$
63,274

 
$
63,149

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 March 31,
2013
 
At December 31,
2012
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
1,769

 
$
2,335

Interest-bearing refundable deposit related to asset sale
 
150

 
150

Notes payable
 
1,294

 
825

Accounts payable
 
1,369

 
1,387

Customer deposits
 
376

 
370

Accrued taxes —
 
 
 
 
Accrued income taxes
 
38

 
10

Other accrued taxes
 
208

 
391

Accrued interest
 
249

 
237

Accrued vacation pay
 
212

 
212

Accrued compensation
 
161

 
433

Liabilities from risk management activities
 
37

 
75

Other regulatory liabilities, current
 
114

 
107

Other current liabilities
 
462

 
482

Total current liabilities
 
6,439

 
7,014

Long-term Debt
 
20,223

 
19,274

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
9,842

 
9,938

Deferred credits related to income taxes
 
207

 
211

Accumulated deferred investment tax credits
 
946

 
894

Employee benefit obligations
 
2,526

 
2,540

Asset retirement obligations
 
1,807

 
1,748

Other cost of removal obligations
 
1,220

 
1,194

Other regulatory liabilities, deferred
 
312

 
289

Other deferred credits and liabilities
 
633

 
668

Total deferred credits and other liabilities
 
17,493

 
17,482

Total Liabilities
 
44,155

 
43,770

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 — March 31, 2013: 880 million shares
 
 
 
 
      — December 31, 2012: 878 million shares
 
 
 
 
Treasury — March 31, 2013: 10.1 million shares
 
 
 
 
          — December 31, 2012: 10.0 million shares
 
 
 
 
Par value
 
4,400

 
4,389

Paid-in capital
 
4,926

 
4,855

Treasury, at cost
 
(451
)
 
(450
)
Retained earnings
 
9,281

 
9,626

Accumulated other comprehensive loss
 
(119
)
 
(123
)
Total Common Stockholders' Equity
 
18,037

 
18,297

Preferred and Preference Stock of Subsidiaries
 
707

 
707

Total Stockholders' Equity
 
18,744

 
19,004

Total Liabilities and Stockholders' Equity
 
$
63,274

 
$
63,149

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

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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

FIRST QUARTER 2013 vs. FIRST QUARTER 2012

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.
In addition, subsidiaries of Southern Company are constructing Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in two units, each with approximately 1,100 MWs) and the Kemper IGCC for a total of 582 MWs. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "PSC Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Georgia Power is scheduled to file its next base rate case by July 1, 2013, which will determine whether the 2010 ARP should be continued, modified, or discontinued.
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. See FUTURE EARNINGS POTENTIAL – "Other Matters" herein for information regarding an explosion at Plant Bowen in April 2013 that is expected to negatively impact the Southern Company system's actual performance on its peak season equivalent forced outage rate, one of its key performance indicators, for 2013, as compared to the target.

RESULTS OF OPERATIONS
Net Income
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$(287)
 
(78.0)
Southern Company's first quarter 2013 net income after dividends on preferred and preference stock of subsidiaries was $81 million ($0.09 per share) compared to $368 million ($0.42 per share) for the first quarter 2012. The decrease was primarily related to a revision of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and the cost of the lignite mine and equipment, the cost of the carbon dioxide pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). Also contributing to the decrease were a reduction in leveraged lease income

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

resulting from a lease restructuring and an increase in depreciation related to new generating plants in service. The decrease was partially offset by an increase in weather-related revenues due to more favorable weather in the first quarter 2013 as compared to the corresponding period in 2012, an increase in retail base revenues at Georgia Power as authorized under the 2010 ARP and the NCCR tariff, and an increase in capacity revenues at Southern Power.
Retail Revenues
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$206
 
6.7
In the first quarter 2013, retail revenues were $3.3 billion compared to $3.1 billion for the corresponding period in 2012.
Details of the change to retail revenues were as follows: 
 
 
First Quarter
2013
 
 
(in millions)
 
(% change)
Retail – prior year
 
$
3,092

 
 
Estimated change in –
 
 
 
 
Rates and pricing
 
46

 
1.5

Sales growth (decline)
 
(14
)
 
(0.4
)
Weather
 
66

 
2.1

Fuel and other cost recovery
 
108

 
3.5

Retail – current year
 
$
3,298

 
6.7
%
Revenues associated with changes in rates and pricing increased in the first quarter 2013 when compared to the corresponding period in 2012 primarily due to base tariff increases at Georgia Power effective April 2012 and January 1, 2013, as approved by the Georgia PSC, related to placing new generating units at Plant McDonough-Atkinson in service, the financing costs related to the construction of Plant Vogtle Units 3 and 4, and demand-side management costs.
Revenues attributable to changes in sales decreased in the first quarter 2013 when compared to the corresponding period in 2012. The decrease was due to a 2.1% decrease in industrial KWH sales and a 0.9% decrease in weather-adjusted residential KWH sales, partially offset by a 0.4% increase in weather-adjusted commercial KWH sales. The decrease in industrial KWH sales for the first quarter 2013 was primarily due to decreases in the chemicals, paper, and primary metals sectors, partially offset by an increase in the stone, clay, and glass sector. The decrease in weather-adjusted residential KWH sales for the first quarter 2013 was primarily due to a decrease in customer usage, partially offset by customer growth. The increase in weather-adjusted commercial KWH sales for the first quarter 2013 was primarily due to increased customer usage. In addition, an extra day of sales as a result of the leap year in 2012 negatively impacted KWH sales in all customer classes in 2013.
In the first quarter 2012, Georgia Power began using new actual advanced meter data to compute unbilled revenues. The weather-adjusted KWH sales variances shown above reflect an adjustment to the estimated allocation of Georgia Power's unbilled January 2012 KWH sales among customer classes that is consistent with the actual allocation in 2013. Without this adjustment, first quarter 2013 residential weather-adjusted KWH sales decreased 1.9% as compared to the corresponding period in 2012 and commercial weather-adjusted KWH sales increased 1.5% as compared to the corresponding period in 2012.
Revenues resulting from changes in weather increased $66 million in the first quarter 2013 as a result of more favorable weather when compared to the corresponding period in 2012.
Fuel and other cost recovery revenues increased $108 million in the first quarter 2013 when compared to the corresponding period in 2012 primarily due to an increase in fuel costs associated with an increase in KWH

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

generation. 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. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental, storm damage, new plants, and PPAs.
Wholesale Revenues 
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$83
 
23.8
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 first quarter 2013, wholesale revenues were $432 million compared to $349 million for the corresponding period in 2012, reflecting a $60 million increase in energy revenues and a $23 million increase in capacity revenues. The increase in energy revenues was primarily related to more favorable weather in the first quarter 2013 as compared to the corresponding period in 2012. The increase in capacity revenues was primarily due to the commencement of PPAs at Southern Power for new plants placed in service in 2012.
Fuel and Purchased Power Expenses 
 
 
First Quarter 2013
vs.
First Quarter 2012
 
 
(change in millions)
 
(% change)
Fuel
 
$
198

 
18.6

Purchased power
 
(46
)
 
(32.6
)
Total fuel and purchased power expenses
 
$
152

 
 
In the first quarter 2013, total fuel and purchased power expenses were $1.4 billion compared to $1.2 billion for the corresponding period in 2012. The increase was primarily the result of a $116 million increase in the volume of KWHs generated as a result of more favorable weather in the first quarter 2013 and a $95 million increase in the average cost of fuel and purchased power, partially offset by a $59 million decrease in the volume of KWHs purchased.
Fuel and purchased power energy transactions at the traditional operating companies are generally offset by fuel 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: 
 
 
First Quarter
2013
 
First Quarter
2012
Total generation (billions of KWHs)
 
43

 
39

Total purchased power (billions of KWHs)
 
3

 
4

Sources of generation (percent) —
 
 
 
 
Coal
 
34

 
35

Nuclear
 
17

 
19

Gas
 
44

 
42

Hydro
 
5

 
4

Cost of fuel, generated (cents per net KWH) —
 
 
 
 
Coal
 
4.14

 
4.09

Nuclear
 
0.85

 
0.80

Gas
 
3.11

 
2.77

Average cost of fuel, generated (cents per net KWH)
 
3.08

 
2.85

Average cost of purchased power (cents per net KWH)(a)
 
4.64

 
3.88

 
(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 first quarter 2013, fuel expense was $1.3 billion compared to $1.1 billion for the corresponding period in 2012. The increase was primarily due to a 12.3% increase in the average cost of natural gas per KWH generated and a 9.3% increase in the volume of KWHs generated as a result of higher demand for generation.
Purchased Power
In the first quarter 2013, purchased power expense was $95 million compared to $141 million for the corresponding period in 2012. The decrease was primarily due to a 33.7% decrease in the volume of KWHs purchased as the marginal cost of generation available was lower than the market cost of available energy, partially offset by a 19.6% increase in the average cost per KWH purchased.
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.
Other Operations and Maintenance Expenses 
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$7
 
0.7
In the first quarter 2013, other operations and maintenance expenses were $974 million compared to $967 million for the corresponding period in 2012. The increase was primarily the result of a $14 million increase in administrative and general costs primarily due to an increase in pension costs and a $6 million increase in nuclear production expenses primarily at Alabama Power related to the amortization of nuclear outage expenses, partially offset by a $14 million decrease related to scheduled outage and maintenance costs.

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Depreciation and Amortization 
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$25
 
5.7
In the first quarter 2013, depreciation and amortization was $466 million compared to $441 million for the corresponding period in 2012. The increase was primarily the result of an increase in depreciation related to additional plant in service due to the completion of Georgia Power's Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, additional plant in service at Southern Power, as well as transmission, distribution, and environmental projects. These increases were partially offset by amortization of the regulatory liability previously established for state income tax credits at Georgia Power, as authorized by the Georgia PSC.
Taxes Other Than Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$10
 
4.4
In the first quarter 2013, taxes other than income taxes were $235 million compared to $225 million for the corresponding period in 2012. The increase was primarily the result of increases in property taxes and municipal franchise fees.
Estimated Loss on Kemper IGCC
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$540
 
N/M
N/M – Not meaningful
In the first quarter 2013, an estimated probable loss on the Kemper IGCC of $540 million was recorded at Southern Company to reflect a revision of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and the Cost Cap Exceptions.
See FUTURE EARNINGS POTENTIAL – "Construction Program" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction 
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$10
 
32.3
In the first quarter 2013, AFUDC equity was $41 million compared to $31 million for the corresponding period in 2012. The increase was primarily due to an increase in CWIP related to Mississippi Power's Kemper IGCC, partially offset by the completion of Georgia Power's Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

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Leveraged Lease Income (Loss) 
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$(27)
 
N/M
N/M – Not meaningful
In the first quarter 2013, leveraged lease income (loss) was $(21) million compared to $6 million for the corresponding period in 2012. The decrease was primarily due to the restructuring of a leveraged lease investment. See Note (J) to the Condensed Financial Statements under "Investments in Leveraged Leases" herein for additional information.
Income Taxes 
First Quarter 2013 vs. First Quarter 2012
(change in millions)
 
(% change)
$(169)
 
(84.5)
In the first quarter 2013, income taxes were $31 million compared to $200 million for the corresponding period in 2012. The decrease was primarily due to lower pre-tax earnings.

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 and the successful completion of ongoing construction projects, including construction of generating facilities. 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 regional and global economic conditions may impact sales for the traditional operating companies and Southern Power, as 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

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

Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding Alabama's State Implementation Plan requirements related to opacity, the EPA's MATS rule, and the 2007 State of Georgia Multi-Pollutant Rule.
On March 6, 2013, the U.S. Court of Appeals for the Eleventh Circuit upheld the EPA's 2008 approval of Alabama's opacity requirements and vacated the EPA's 2011 attempt to rescind its approval, thereby resolving Alabama Power's appeal in Alabama Power's favor. The ultimate outcome of this matter will depend on the outcome of any further appellate or regulatory actions and cannot be determined at this time.
On April 24, 2013, the EPA published a final reconsideration rule addressing new source standards within the MATS rule. Although the EPA had considered revisions to the startup and shutdown provisions of the MATS rule, a final decision on these provisions was deferred. The ultimate impact of this rulemaking will depend on the outcome of any additional rulemaking and/or legal challenges and, therefore, cannot be determined at this time.
On April 30, 2013, the State of Georgia finalized revisions to the 2007 State of Georgia Multi-Pollutant Rule and a companion rule requiring a 95% reduction in sulfur dioxide emissions from certain coal-fired generating units. The revisions modify the compliance dates under those two rules for units yet to be controlled to synchronize them with the MATS rule compliance deadline. The revisions also allow natural gas to be used as a compliance alternative at Plant Yates as contemplated by the 2013 IRP. The ultimate outcome of these matters cannot be determined at this time. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information. 
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's proposed revision of the current steam electric effluent guidelines. On April 19, 2013, the EPA signed a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of the facilities of Southern Company's subsidiaries, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.
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 in recent years 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 a total over recovered fuel balance at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power included on Southern Company's Condensed Balance Sheet herein of approximately $269 million at March 31, 2013. At December 31, 2012, a total over recovered fuel balance at Georgia Power, Gulf Power, and Mississippi Power included on Southern Company's Condensed Balance Sheet herein was approximately $303 million.

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

Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances.
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 – Energy Cost Recovery" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Alabama Power
Rate RSE
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate RSE" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information regarding Alabama Power's Rate Stabilization and Equalization (Rate RSE). On March 19, 2013, the Alabama PSC issued a notice that the Alabama PSC will hold public proceedings regarding the operation and utilization of Rate RSE. The ultimate outcome of these proceedings cannot be determined at this time.
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 March 31, 2013, the NDR had an accumulated balance of $93 million as compared to $103 million at December 31, 2012, which is included on Southern Company's Condensed Balance Sheets herein under other regulatory liabilities, deferred. The decrease in the NDR in the first quarter 2013 is a result of storm activity. The related accruals are reflected as operations and maintenance expenses on Southern Company's Condensed Statement of Income herein.
Georgia Power
Integrated Resource Plans
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 "– Integrated Resource Plans" 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; the 2011 IRP; and the 2013 IRP.
On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013. The Georgia PSC is scheduled to vote on all other aspects of the 2013 IRP in July 2013. The ultimate outcome of this matter cannot be determined at this time.
Separately, on April 22, 2013, Georgia Power executed two PPAs to purchase energy from two wind farms with capacity totaling 250 MWs in southwest Oklahoma that will commence in 2016 and end in 2035. In addition, on April 29, 2013, Georgia Power executed a PPA for the purchase of 50 MWs of capacity and energy that will commence in 2015 and end in 2035. These PPAs are subject to Georgia PSC approval and, if approved, will result in contractual obligations of approximately $13 million in 2015, $47 million in 2016, $48 million in 2017, and $1.3 billion thereafter.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Plant Vogtle Units 3 and 4 at Georgia Power, the Kemper IGCC at Mississippi Power, and solar units at Southern 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.
The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in two units, each with approximately 1,100 MWs) and the construction of Mississippi Power's Kemper IGCC (for a total of 582 MWs). See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for the current cost estimate of the Southern Company system's construction program, which includes the revised construction cost estimate to complete the Kemper IGCC. Also see Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear 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.
On March 1, 2013, Southern Company completed the restructuring of the nonrecourse debt and the related rental payments associated with its leveraged lease investment in a 440-MW generation facility located in Choctaw County, Mississippi. In connection with the restructuring, Southern Company has committed, as owner/lessor, to invest approximately $60 million in capital over the next three years to improve the operational performance of the facility and upgrade environmental controls. As part of the restructuring, the interest rate on the nonrecourse debt was significantly reduced, resulting in lower debt payments for Southern Company and lower rental payments for the lessee over the remaining 19-year term of the nonrecourse debt and the lease. As a consequence of the restructuring, Southern Company recalculated its net investment in the lease to reflect changes in the future cash flows to Southern Company as owner/lessor. As a result of the recalculation, Southern Company recorded an after-tax charge to income during the first quarter 2013 of approximately $16 million. This noncash charge reflects a reallocation of previously recognized lease income that will be reflected in income over the remaining term of the lease.
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, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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) to the Condensed Financial Statements 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 NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011. On March 19, 2013, the NRC issued an order relating to hardened vents for certain classes of containment structures, including the one in use at Plant Hatch. Southern Company is continuing to analyze the impact of this order. The ultimate outcome of this matter cannot be determined at this time; however, management does not currently anticipate that the compliance costs associated with this order would have a material impact on Southern Company's financial statements.
On April 4, 2013, an explosion occurred at Plant Bowen Unit 2 that resulted in substantial damage to the Plant Bowen Unit 2 generator, Plant Bowen's Units 1 and 2 control room and surrounding areas, as well as Plant Bowen's switchyard. The extent of the damage sustained by Plant Bowen Unit 1 is unknown. Plant Bowen Units 1 and 2 (approximately 1,400 MWs) remain offline, pending assessment of the damage and completion of repairs. Georgia Power expects that any material repair costs related to the damage will be covered by property insurance. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Pension and Other Postretirement Benefits.
Estimated Construction Costs for the Kemper IGCC
On April 23, 2013, Mississippi Power revised its cost estimate to complete construction of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and the Cost Cap Exceptions. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any Kemper IGCC construction costs that exceed the $2.88 billion cost cap, except for amounts subject to the Cost Cap Exceptions and net of the DOE Grants. As a result, Southern Company recorded a pretax charge of $540 million in the first quarter 2013. In subsequent periods, any changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap will be reflected in Southern Company's statements of income and these changes could be material. Southern Company's analysis will be ongoing throughout the construction period. It is possible that Southern Company could experience further cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors 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, delays associated with start-up activities, and/or unforeseen engineering problems.

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

Given the significant judgment involved in estimating the future costs to complete construction, schedule, and the ultimate rate recoverability for the Kemper IGCC, and the potential impact on Southern Company's results of operations, Southern Company considers the future total construction costs for the Kemper IGCC to be a critical accounting estimate. See FUTURE EARNINGS POTENTIAL – "Construction Program" of Southern Company in Item 7 of the Form 10-K, Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at March 31, 2013. 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $737 million for the first three months of 2013, an increase of $169 million from the corresponding period in 2012. The increase in net cash provided from operating activities was primarily due to a reduction in fossil fuel stock. Net cash used for investing activities totaled $1.3 billion for the first three months of 2013 primarily due to property additions to utility plant. Net cash provided from financing activities totaled $429 million for the first three months of 2013. This was primarily due to 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 three months of 2013 include an increase of $297 million in total property, plant, and equipment for construction of generation, transmission, and distribution facilities and a decrease in cash and cash equivalents of $113 million primarily due to an effort to reduce bank balances. Other significant changes include a $949 million increase in long-term debt (excluding amounts due within a year) to repay maturing debt and to fund the Southern Company subsidiaries' continuous construction programs, a $345 million decrease in retained earnings resulting from the estimated probable loss on the Kemper IGCC, a decrease of $272 million in accrued compensation primarily due to the payout in March of employee performance incentives earned in 2012, and a reduction in other accrued taxes of $183 million primarily due to payments of ad valorem taxes.
The market price of Southern Company's common stock at the end of the first quarter 2013 was $46.92 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $20.72 per share, representing a market-to-book ratio of 226%, compared to $42.81, $21.09, and 203%, respectively, at the end of 2012. The dividend for the first quarter 2013 was $0.49 per share compared to $0.4725 per share in the first quarter 2012. In April 2013, the quarterly dividend payable in June 2013 was increased to $0.5075 per share.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new generating facilities and to comply with existing environmental statutes and 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 $1.8 billion will be required through March 31, 2014 to fund maturities of long-term debt. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information.

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

The Southern Company system's construction program is currently estimated to be $5.9 billion for 2013, $6.0 billion for 2014, and $5.2 billion for 2015. Included in these estimated amounts are expenditures related to the construction of the Kemper IGCC of $913 million and $358 million in 2013 and 2014, respectively, which include the revised construction cost estimate to complete the Kemper IGCC and are net of SMEPA's 15% proposed ownership share of the Kemper IGCC, which reflects costs of approximately $492 million and $28 million in 2013 and 2014, respectively. The estimated share of SMEPA in 2013 reflects estimated construction costs relating to SMEPA's proposed ownership interest to be incurred through December 31, 2013 (including construction costs for all prior years relating to its proposed ownership interest).
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 the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; 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. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "PSC Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
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 in 2013, as well as in subsequent years, will be contingent on Southern Company's investment opportunities.
Except as described herein, 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 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. The conditional commitment will expire on June 30, 2013, unless further extended by the DOE. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Mississippi Power has received DOE Clean Coal Power Initiative Round 2 (CCPI2) grant funds of $245 million that have been used for the construction of the Kemper IGCC. An additional $25 million in CCPI2 grant funds is

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

expected to be received for the initial operation of the Kemper IGCC. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs 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 March 31, 2013, Southern Company and its subsidiaries had approximately $515 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2013 were as follows:
 
 
Expires(a)
 
 
 
Executable Term
Loans
 
Due Within One
Year
Company
 
2013
 
2014
 
2016
 
2018
 
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
 
156

 
151

 
—

 
1,000

 
1,307

 
1,307

 
56

 
—

 
56

 
102

Georgia Power
 
—

 
—

 
150

 
1,600

 
1,750

 
1,740

 
—

 
—

 
—

 
—

Gulf Power
 
45

 
60

 
165

 
—

 
270

 
270

 
45

 
—

 
45

 
30

Mississippi Power
 
110

 
25

 
165

 
—

 
300

 
300

 
25

 
40

 
65

 
70

Southern Power
 
—

 
—

 
—

 
500

 
500

 
500

 
—

 
—

 
—

 
—

Other
 
50

 
—

 
—

 
—

 
50

 
50

 
25

 
—

 
25

 
25

Total
 
$
361

 
$
236

 
$
480

 
$
4,100

 
$
5,177

 
$
5,167

 
$
151

 
$
40

 
$
191

 
$
227

(a)
No credit arrangements expire in 2015 or 2017.
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.
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 March 31, 2013 was approximately $1.8 billion.
In February 2013, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended their multi-year credit arrangements, which extended the maturity dates from 2016 to 2018.
In March 2013, Alabama Power amended a $200 million credit arrangement, which extended the maturity date from 2014 to 2018. In March 2013, Gulf Power also amended a $35 million credit arrangement, which reduced the amount to $30 million and extended the maturity date from 2013 to 2014. In addition, in March 2013, Georgia Power, Gulf Power, and Mississippi Power each amended certain of their credit arrangements, which extended the maturity dates from 2014 to 2016 and, in the case of Mississippi Power, also revised the definition of debt to exclude securitized debt relating to the Kemper IGCC for purposes of calculating the debt covenant under these credit arrangements. See Note (B) to the Condensed Financial Statements under ''Integrated Coal Gasification Combined Cycle'' herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
Subsequent to March 31, 2013, Gulf Power entered into a new credit arrangement for $5 million with a maturity date of 2014.

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

Subsequent to March 31, 2013, SEGCO entered into two new $25 million credit arrangements with maturity dates of 2014.
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.
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.
Details of short-term borrowings were as follows:
 
 
Short-term Debt at March 31, 2013(a)
 
Short-term Debt During the Period(a)(b)
 
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
 
(in millions)
 
 
 
(in millions)
 
 
 
(in millions)
Commercial paper
 
$
989

 
0.3
%
 
$
955

 
0.3
%
 
$
1,119

Short-term bank debt
 
300

 
0.9
%
 
87

 
0.9
%
 
300

Total
 
$
1,289

 
0.4
%
 
$
1,042

 
0.3
%
 
 
(a) Excludes notes payable related to other energy service contracts of $2 million.
(b) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2013.
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 and its subsidiaries 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 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 March 31, 2013 were as follows:
 
Credit Ratings
  Maximum Potential  
Collateral
Requirements
 
(in millions)
At BBB and Baa2
$
9

At BBB- and/or Baa3
625

Below BBB- and/or Baa3
2,571

In March 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 for 2012 and 9.962% per annum at March 31, 2013, 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

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

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 the ability of Southern Company and its subsidiaries to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.
Market Price Risk
The Southern Company system is exposed to market risks, primarily commodity price risk and interest rate risk. The Southern Company system may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable company's policies in areas such as counterparty exposure and risk management practices. The Southern Company system'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 first quarter 2013 when compared to the December 31, 2012 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2013 were as follows:
 
 
First Quarter
2013
Changes
 
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(85
)
 
Contracts realized or settled
 
25

 
Current period changes(a)
 
47

 
Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(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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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 months ended March 31, 2013 were as follows:
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
57

Natural gas options
 
15

Total changes
 
$
72

The net hedge volumes of energy-related derivative contracts were as follows:
 
 
 
March 31,
2013
 
December 31,
2012
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
 
170

 
171

Commodity – Natural gas options
 
 
89

 
105

Total hedge volume
 
 
259

 
276

The weighted average swap contract cost above market prices was approximately $0.05 per mmBtu as of March 31, 2013 and $0.39 per mmBtu as of December 31, 2012. The change in option fair value 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
 
March 31,
2013
 
December 31,
2012
 
 
(in millions)
Regulatory hedges
 
$
(17
)
 
$
(86
)
Cash flow hedges
 
—

 
—

Not designated
 
4

 
1

Total fair value
 
$
(13
)
 
$
(85
)
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 (losses) recognized in the statements of income for the three months ended March 31, 2013 and 2012 were not material.

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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, which are all Level 2 of the fair value hierarchy, at March 31, 2013 were as follows:
 
 
March 31, 2013
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(13
)
 
(8
)
 
(5
)
 
—

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(13
)
 
$
(8
)
 
$
(5
)
 
$
—

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 quarter 2013, Southern Company issued approximately 2.6 million shares of common stock for approximately $54 million through the employee and director stock plans, of which 0.7 million shares related to Southern Company's performance share plan. 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. As of December 31, 2012, Southern Company had repurchased a total of approximately 9 million shares at a total cost of approximately $430 million under this program. In January 2013, Southern Company announced that it plans to continue this program through 2015. There were no repurchases under this program in the first quarter 2013. Pursuant to approval by the Southern Company Board of Directors, 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.
The following table outlines the long-term debt financing activities for Southern Company, the traditional operating companies, and Southern Power for the first three months of 2013:
Company(a)
 
Senior Note
Issuances
 
Senior Note
Redemptions
and Maturities
 
Revenue Bond Issuances
 
Other Long-Term Debt Issuances
 
 
 
 
(in millions)
 
 
Georgia Power
 
$
650

 
$
650

 
$
18

 
$
—

Mississippi Power
 
—

 
—

 
16

 
350

Southern Power
 
—

 
—

 
—

 
2

Total
 
$
650

 
$
650

 
$
34

 
$
352

(a) Southern Company, Alabama Power, and Gulf Power did not issue or redeem any long-term debt during the first quarter 2013.

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

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.
In March 2013, Georgia Power entered into three 60-day floating rate bank loans bearing interest based on one-month LIBOR. Each of these short-term loans was for $100 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
Subsequent to March 31, 2013, $17.5 million aggregate principal amount of Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 1997 were redeemed.
Also subsequent to March 31, 2013, Southern Power issued a $5.6 million promissory note, due April 30, 2033, to Turner Renewable Energy, LLC related to the financing of the acquisition by Southern Power of Campo Verde Solar, LLC, which is constructing a 139-MW solar photovoltaic facility in Southern California. See Note (I) to the Condensed Financial Statements herein for additional information.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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PART I
Item 3. Quantitative And Qualitative Disclosures About Market Risk.
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.
Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power
As of the end of the period covered by this quarterly report, Southern Company, Alabama Power, Georgia Power, Gulf 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.  
Mississippi Power
As described further in Notes 3 and 12 to the financial statements of Mississippi Power in Item 8 and Management's Report on Internal Control Over Financial Reporting in Item 9A of the Form 10-K/A, Mississippi Power restated and corrected its previously issued financial statements for the year ended December 31, 2012 to recognize a pretax charge for an estimated probable loss relating to the Kemper IGCC. Management believes Mississippi Power's failure to maintain sufficient evidence supporting certain estimated amounts included in the Kemper IGCC cost estimate and to fully communicate the related effects in the development of the Kemper IGCC cost estimate would constitute a material weakness in internal control over financial reporting under standards adopted by the Public Company Accounting Oversight Board and concluded Mississippi Power's internal control over financial reporting was not effective as of December 31, 2012.
As of the end of the period covered by this quarterly report, Mississippi Power conducted an evaluation under the supervision and with the participation of 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 this evaluation, which considered the material weakness described above, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were not effective.
Management has initiated appropriate actions to remediate the material weakness in internal control over financial reporting. Such actions include, but are not limited to, the following:
•
establishing a new governance team focused on accounting, legal, and regulatory affairs that will meet regularly with the Kemper IGCC project and construction teams and will provide further oversight of the Kemper IGCC cost estimation process;
•
reemphasizing and enhancing communication across functional areas and departments; and
•
applying appropriate performance management actions.
Remediation of the material weakness is expected to be completed during the second quarter 2013.
(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 first quarter 2013 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.

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ALABAMA POWER COMPANY

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ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Operating Revenues:
 
 
 
Retail revenues
$
1,141

 
$
1,092

Wholesale revenues, non-affiliates
59

 
61

Wholesale revenues, affiliates
56

 
14

Other revenues
52

 
49

Total operating revenues
1,308

 
1,216

Operating Expenses:
 
 
 
Fuel
372

 
306

Purchased power, non-affiliates
20

 
15

Purchased power, affiliates
31

 
40

Other operations and maintenance
330

 
321

Depreciation and amortization
158

 
157

Taxes other than income taxes
90

 
86

Total operating expenses
1,001

 
925

Operating Income
307

 
291

Other Income and (Expense):
 
 
 
Allowance for equity funds used during construction
8

 
5

Interest expense, net of amounts capitalized
(66
)
 
(73
)
Other income (expense), net
(1
)
 
(3
)
Total other income and (expense)
(59
)
 
(71
)
Earnings Before Income Taxes
248

 
220

Income taxes
97

 
84

Net Income
151

 
136

Dividends on Preferred and Preference Stock
10

 
10

Net Income After Dividends on Preferred and Preference Stock
$
141

 
$
126


CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Net Income
$
151

 
$
136

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

 
4

Total other comprehensive income (loss)
—

 
4

Comprehensive Income
$
151

 
$
140

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

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ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Operating Activities:
 
 
 
Net income
$
151

 
$
136

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
206

 
189

Deferred income taxes
25

 
31

Allowance for equity funds used during construction
(8
)
 
(5
)
Stock based compensation expense
4

 
4

Other, net
5

 
(11
)
Changes in certain current assets and liabilities —
 
 
 
-Receivables
(13
)
 
89

-Fossil fuel stock
28

 
(81
)
-Materials and supplies
16

 
2

-Other current assets
(71
)
 
(51
)
-Accounts payable
(124
)
 
(149
)
-Accrued taxes
90

 
43

-Accrued compensation
(61
)
 
(63
)
-Retail fuel cost over recovery
21

 
1

-Other current liabilities
1

 
5

Net cash provided from operating activities
270

 
140

Investing Activities:
 
 
 
Property additions
(274
)
 
(244
)
Nuclear decommissioning trust fund purchases
(57
)
 
(49
)
Nuclear decommissioning trust fund sales
57

 
49

Cost of removal, net of salvage
(9
)
 
(6
)
Change in construction payables
(1
)
 
14

Other investing activities
37

 
1

Net cash used for investing activities
(247
)
 
(235
)
Financing Activities:
 
 
 
Increase in notes payable, net
45

 
—

Proceeds —
 
 
 
Capital contributions from parent company
5

 
5

Senior notes issuances
—

 
250

Payment of preferred and preference stock dividends
(10
)
 
(10
)
Payment of common stock dividends
(132
)
 
(135
)
Other financing activities
(3
)
 
(4
)
Net cash provided from (used for) financing activities
(95
)
 
106

Net Change in Cash and Cash Equivalents
(72
)
 
11

Cash and Cash Equivalents at Beginning of Period
137

 
344

Cash and Cash Equivalents at End of Period
$
65

 
$
355

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $3 and $2 capitalized for 2013 and 2012, respectively)
$
64

 
$
66

Income taxes, net
(3
)
 
22

Noncash transactions—accrued property additions at end of period
30

 
32

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

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ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At March 31,
2013
 
At December 31,
2012
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
65

 
$
137

Receivables —
 
 
 
 
Customer accounts receivable
 
349

 
321

Unbilled revenues
 
122

 
138

Under recovered regulatory clause revenues
 
11

 
23

Other accounts and notes receivable
 
35

 
42

Affiliated companies
 
74

 
55

Accumulated provision for uncollectible accounts
 
(8
)
 
(8
)
Fossil fuel stock, at average cost
 
447

 
475

Materials and supplies, at average cost
 
370

 
395

Vacation pay
 
61

 
61

Prepaid expenses
 
121

 
81

Other regulatory assets, current
 
13

 
24

Other current assets
 
14

 
13

Total current assets
 
1,674

 
1,757

Property, Plant, and Equipment:
 
 
 
 
In service
 
21,508

 
21,407

Less accumulated provision for depreciation
 
7,816

 
7,761

Plant in service, net of depreciation
 
13,692

 
13,646

Nuclear fuel, at amortized cost
 
356

 
354

Construction work in progress
 
535

 
438

Total property, plant, and equipment
 
14,583

 
14,438

Other Property and Investments:
 
 
 
 
Equity investments in unconsolidated subsidiaries
 
54

 
53

Nuclear decommissioning trusts, at fair value
 
642

 
605

Miscellaneous property and investments
 
78

 
78

Total other property and investments
 
774

 
736

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
524

 
525

Deferred under recovered regulatory clause revenues
 
15

 
11

Other regulatory assets, deferred
 
1,071

 
1,083

Other deferred charges and assets
 
128

 
162

Total deferred charges and other assets
 
1,738

 
1,781

Total Assets
 
$
18,769

 
$
18,712

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


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ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity
 
At March 31,
2013
 
At December 31,
2012
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
250

 
$
250

Notes payable
 
45

 
—

Accounts payable —
 
 
 
 
Affiliated
 
188

 
191

Other
 
204

 
318

Customer deposits
 
86

 
85

Accrued taxes —
 
 
 
 
Accrued income taxes
 
73

 
5

Other accrued taxes
 
56

 
33

Accrued interest
 
60

 
62

Accrued vacation pay
 
50

 
50

Accrued compensation
 
36

 
94

Liabilities from risk management activities
 
5

 
14

Other regulatory liabilities, current
 
29

 
3

Other current liabilities
 
38

 
38

Total current liabilities
 
1,120

 
1,143

Long-term Debt
 
5,929

 
5,929

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
3,418

 
3,404

Deferred credits related to income taxes
 
78

 
79

Accumulated deferred investment tax credits
 
139

 
141

Employee benefit obligations
 
319

 
321

Asset retirement obligations
 
599

 
589

Other cost of removal obligations
 
773

 
759

Other regulatory liabilities, deferred
 
203

 
183

Other deferred credits and liabilities
 
91

 
81

Total deferred credits and other liabilities
 
5,620

 
5,557

Total Liabilities
 
12,669

 
12,629

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
 
2,236

 
2,227

Retained earnings
 
1,984

 
1,976

Accumulated other comprehensive loss
 
(27
)
 
(27
)
Total common stockholder's equity
 
5,415

 
5,398

Total Liabilities and Stockholder's Equity
 
$
18,769

 
$
18,712

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

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



FIRST QUARTER 2013 vs. FIRST QUARTER 2012

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
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$15
11.9
Alabama Power's net income after dividends on preferred and preference stock for the first quarter 2013 was $141 million compared to $126 million for the corresponding period in 2012. The increase for the first quarter 2013 was primarily related to an increase in weather-related revenues due to more favorable weather in the first quarter 2013 as compared to the corresponding period in 2012, partially offset by increases in other operations and maintenance expenses.
Retail Revenues
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$49
4.5
In the first quarter 2013, retail revenues were $1.14 billion compared to $1.09 billion for the corresponding period in 2012.

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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:
 
 
First Quarter
2013
 
 
(in millions)
 
(% change)
Retail – prior year
 
$
1,092

 
 
Estimated change in –
 
 
 
 
Rates and pricing
 
(1
)
 
(0.1
)
Sales growth (decline)
 
(9
)
 
(0.9
)
Weather
 
39

 
3.6

Fuel and other cost recovery
 
20

 
1.9

Retail – current year
 
$
1,141

 
4.5
 %
Revenues associated with changes in rates and pricing decreased slightly in the first quarter 2013 when compared to the corresponding period in 2012. The decrease was not material.
Revenues attributable to changes in sales decreased in the first quarter 2013 when compared to the corresponding period in 2012. Weather-adjusted residential and commercial KWH energy sales decreased 2.4% and 0.4%, respectively, due to decreases in customer usage. Industrial KWH energy sales increased 0.4% due to an increase in usage resulting from changes in production levels primarily in the stone, clay, and glass and primary metal sectors. In addition, an extra day of sales as a result of the leap year in 2012 negatively impacted KWH sales in all customer classes in 2013.
Revenues resulting from changes in weather increased in the first quarter 2013 when compared to the corresponding period in 2012. Alabama Power's service territory experienced more favorable weather in the first quarter 2013 as compared to the corresponding period in 2012. As a result, residential sales revenues increased 8.5% in the first quarter 2013 as compared to the corresponding period in 2012.
Fuel and other cost recovery revenues increased in the first quarter 2013 when compared to the corresponding period in 2012 primarily due to an increase in fuel costs associated with an increase in KWH generation. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.
Wholesale Revenues – Non-Affiliates
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(2)
(3.3)
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 first quarter 2013, the decrease in wholesale revenues from non-affiliates compared to the corresponding period in 2012 was not material.

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



Wholesale Revenues – Affiliates
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$42
300.0
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
In the first quarter 2013, wholesale revenues from affiliates were $56 million compared to $14 million for the corresponding period in 2012. The increase was primarily due to a 262.4% increase in KWH sales and a 9.5% increase in the price of energy.
Fuel and Purchased Power Expenses

 
First Quarter 2013
vs.
First Quarter 2012
 
 
(change in millions)
(% change)
Fuel
 
$
66

21.6

Purchased power – non-affiliates
 
5

33.3

Purchased power – affiliates
 
(9
)
(22.5
)
Total fuel and purchased power expenses
 
$
62

 
In the first quarter 2013, total fuel and purchased power expenses were $423 million compared to $361 million for the corresponding period in 2012. The increase was primarily due to a $62 million increase associated with an increase in the volume of KWHs generated as a result of more favorable weather in first quarter 2013, a $5 million increase in the average cost of fuel, and a $4 million increase in the average cost of purchased power, partially offset by an $8 million decrease related to the volume of 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 clauses. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billings rates are required. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Energy Cost Recovery" herein for additional information.

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



Details of Alabama Power's generation and purchased power were as follows:
 
 
First Quarter
2013
 
First Quarter
2012
Total generation (billions of KWHs)
 
16

 
14

Total purchased power (billions of KWHs)
 
1

 
1

Sources of generation (percent) –
 
 
 
 
Coal
 
47

 
42

Nuclear
 
24

 
27

Gas
 
17

 
20

Hydro
 
12

 
11

Cost of fuel, generated (cents per net KWH) –
 
 
 
 
Coal
 
3.35

 
3.43

Nuclear
 
0.81

 
0.74

Gas
 
3.31

 
3.00

Average cost of fuel, generated (cents per net KWH)(a)
 
2.65

 
2.51

Average cost of purchased power (cents per net KWH)(b)
 
4.96

 
4.60

(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.
Fuel
In the first quarter 2013, fuel expense was $372 million compared to $306 million for the corresponding period in 2012. The $66 million increase was primarily due to a 31.4% increase in KWHs generated by coal and a 10.3% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements. This increase was offset by a 31.5% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.
Purchased Power – Non-Affiliates
In the first quarter 2013, purchased power expense from non-affiliates was $20 million compared to $15 million for the corresponding period in 2012. The increase was related to a 73.0% increase in the amount of energy purchased, partially offset by a 23.4% 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 first quarter 2013, purchased power expense from affiliates was $31 million compared to $40 million for the corresponding period in 2012. The decrease was related to a 48.2% decrease in the volume of KWHs purchased, partially offset by a 47.5% increase in the average cost per KWH.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Other Operations and Maintenance Expenses
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$9
2.8
In the first quarter 2013, other operations and maintenance expenses were $330 million compared to $321 million for the corresponding period in 2012. Nuclear production expenses increased $6 million primarily due to the amortization of nuclear outage expenses. 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. Administrative and general expenses increased $3 million primarily due to increases in employee medical and pension expenses, partially offset by a decrease in labor and other general expenses.
Allowance for Funds Used During Construction Equity
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$3
60.0
In the first quarter 2013, AFUDC equity was $8 million compared to $5 million for the corresponding period in 2012. The increase was primarily due to an increase in capital expenditures for steam generating and environmental, transmission, and nuclear generating facilities.
Interest Expense, Net of Amounts Capitalized
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(7)
(9.6)
In the first quarter 2013, interest expense, net of amounts capitalized was $66 million compared to $73 million for the corresponding period in 2012. The decrease was primarily due to a decrease in interest rates and the timing of issuances and redemptions of long term-debt.
Other Income (Expense), Net
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$2
66.7
In the first quarter 2013, other income (expense), net was $(1) million compared to $(3) million for the corresponding period in 2012. The change was primarily due to an increase in non-operating income related to gains on sales of non-utility property.
Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$13
15.5
In the first quarter 2013, income taxes were $97 million compared to $84 million for the corresponding period in 2012. The increase was primarily due to higher pre-tax income as a result of increased weather-related revenues.

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



FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of 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 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 Alabama Power's service territory. Changes in regional and global economic conditions may impact sales for Alabama Power as 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.
Environmental Statutes and Regulations
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 regarding Alabama's State Implementation Plan requirements related to opacity and the EPA's MATS rule.
On March 6, 2013, the U.S. Court of Appeals for the Eleventh Circuit upheld the EPA's 2008 approval of Alabama's opacity requirements and vacated the EPA's 2011 attempt to rescind its approval, thereby resolving Alabama Power's appeal in Alabama Power's favor. The ultimate outcome of this matter will depend on the outcome of any further appellate or regulatory actions and cannot be determined at this time.
On April 24, 2013, the EPA published a final reconsideration rule addressing new source standards within the MATS rule. Although the EPA had considered revisions to the startup and shutdown provisions of the MATS rule, a final decision on these provisions was deferred. The ultimate impact of this rulemaking will depend on the outcome of any additional rulemaking and/or legal challenges and, therefore, 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 regarding the EPA's proposed revision of the current steam electric effluent guidelines. On April 19, 2013, the EPA signed a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Alabama Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate

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



impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's Warrior River hydroelectric license.
On March 18, 2013, the Smith Lake Improvement and Stakeholders' Association filed an appeal to the U.S. Court of Appeals for the District of Columbia Circuit regarding the FERC's orders related to the Warrior River relicensing proceedings. The ultimate outcome of this matter cannot be determined at this time.
PSC Matters
Rate RSE
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate RSE" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Note 8 of the Form 10-K for additional information on Alabama Power's Rate Stabilization and Equalization (Rate RSE). On March 19, 2013, the Alabama PSC issued a notice that the Alabama PSC will hold public proceedings regarding the operation and utilization of Rate RSE. The ultimate outcome of these proceedings cannot be determined at this time.
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 PPA) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power's under recovered Rate CNP PPA balance at March 31, 2013 was $7 million as compared to $9 million at December 31, 2012. This under recovered balance at March 31, 2013 is included in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheet herein. For Rate CNP PPA, this classification is based on an estimate, which includes such factors as purchased power capacity 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. Alabama Power's under recovered Rate CNP Environmental balance at March 31, 2013 was $19 million as compared to $21 million at December 31, 2012. This under recovered balance at March 31, 2013 consists of $11 million in under recovered regulatory clause revenues and $8 million in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheet herein. 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.
Retail Energy Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Energy Cost Recovery" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Energy Cost Recovery" in Item 8 of the Form 10-K for information regarding Alabama Power's energy cost recovery. Alabama Power's over recovered fuel costs at March 31, 2013 totaled $21 million as compared to an under recovered balance of $4 million at December 31, 2012. The over recovered fuel costs at March 31, 2013 are included in other regulatory liabilities, current and the under recovered fuel costs at December 31, 2012 are included in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheet herein. These classifications are based on estimates, which include such factors as

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 March 31, 2013, the NDR had an accumulated balance of $93 million as compared to $103 million at December 31, 2012, which is included on Alabama Power's Condensed Balance Sheet herein under other regulatory liabilities, deferred. The decrease in the NDR in the first quarter 2013 is a result of storm activity. The related accruals are reflected as operations and maintenance expenses on Alabama Power's Condensed Statement of Income herein.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, 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) to the Condensed Financial Statements 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.
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.

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



FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at March 31, 2013. 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 $270 million for the first three months of 2013, an increase of $130 million as compared to the first three months of 2012. The increase in net cash provided from operating activities was primarily due to a decrease in fossil fuel stock, an increase in accounts payable as compared to the first three months of 2012, and the timing of income tax payments and refunds. This was partially offset by an increase in receivables. Net cash used for investing activities totaled $247 million for the first three months of 2013 primarily due to gross property additions related to steam generation, transmission, and distribution equipment. Net cash used for financing activities totaled $95 million for the first three months of 2013 primarily due to the payment of common stock dividends, partially offset by an increase in notes payable. 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 three months of 2013 include increases of $145 million in property, plant, and equipment associated with routine property additions and $68 million in accrued income taxes and decreases of $114 million in other accounts payable and $72 million in cash and cash equivalents.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $250 million will be required through March 31, 2014 to fund maturities of long-term debt.
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 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.

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



Sources of Capital
Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those used 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 March 31, 2013, Alabama Power had approximately $65 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2013 were as follows:
Expires(a)
 
 
 
 
 
Executable Term
Loans
 
Due Within One
Year
2013
 
2014
 
2018
 
Total
 
Unused
 
One
Year

 
Two
Years

 
Term
Out

 
No Term
Out

(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
$
156

 
$
151

 
$
1,000

 
$
1,307

 
$
1,307

 
$
56

 
$
—

 
$
56

 
$
102

(a)
No credit arrangements expire in 2015, 2016, or 2017.
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.
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 March 31, 2013 was approximately $793 million. In addition, Alabama Power has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs.
In February 2013, Alabama Power amended an $800 million multi-year credit arrangement, which extended the maturity date from 2016 to 2018. In addition, in March 2013, Alabama Power amended a $200 million credit arrangement, which extended the maturity date from 2014 to 2018.
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 company under these arrangements are several and there is no cross affiliate credit support.
Most of these arrangements contain covenants that limit debt levels and contain cross default provisions that are restricted only to the indebtedness (including guarantee obligations) 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.

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



Details of short-term borrowings were as follows: 
 
 
Short-term Debt at
March 31, 2013
 
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
 
$45
 
0.2%
 
$18
 
0.2%
 
$85
(a)
Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2013.
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 March 31, 2013, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $268 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 first quarter 2013 has not changed materially compared to the December 31, 2012 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 a result, Alabama Power had no material change in market risk exposure for the first quarter 2013 when compared with the December 31, 2012 reporting period.

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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 months ended March 31, 2013 were as follows:
 
 
First Quarter 2013 Changes
 
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(13
)
 
Contracts realized or settled
 
6

 
Current period changes(a)
 
12

 
Contracts outstanding at the end of the period, assets (liabilities), net
 
$
5

 
(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 months ended March 31, 2013 were as follows:
 
 
First Quarter 2013
Changes
 
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
15

 
Natural gas options
 
3

 
Total changes
 
$
18

 
The net hedge volumes of energy-related derivative contracts were as follows:
 
 
March 31,
2013
 
 
December 31,
2012
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
47

 
 
45

Commodity – Natural gas options
 
10

 
 
12

Total hedge volume
 
57

 
 
57

The weighted average swap contract cost below market prices was approximately $0.04 per mmBtu as of March 31, 2013. The weighted average swap contract cost above market prices was approximately $0.30 per mmBtu as of December 31, 2012. The change in option fair value 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 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 energy recovery clause.
Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2013 and 2012 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, which are all Level 2 of the fair value hierarchy, at March 31, 2013 were as follows:
 
 
March 31, 2013
Fair Value Measurements
 
 
Total
Fair Value
 
Maturity
 
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
5

 
2

 
3

 
—

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
5

 
$
2

 
$
3

 
$
—

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
Alabama Power did not issue or redeem any securities during the three months ended March 31, 2013.
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.

50
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GEORGIA POWER COMPANY

51
Table of Contents


GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Operating Revenues:
 
 
 
Retail revenues
$
1,729

 
$
1,594

Wholesale revenues, non-affiliates
62

 
66

Wholesale revenues, affiliates
6

 
3

Other revenues
85

 
82

Total operating revenues
1,882

 
1,745

Operating Expenses:
 
 
 
Fuel
519

 
440

Purchased power, non-affiliates
50

 
93

Purchased power, affiliates
175

 
159

Other operations and maintenance
431

 
434

Depreciation and amortization
200

 
188

Taxes other than income taxes
95

 
87

Total operating expenses
1,470

 
1,401

Operating Income
412

 
344

Other Income and (Expense):
 
 
 
Allowance for equity funds used during construction
6

 
13

Interest expense, net of amounts capitalized
(91
)
 
(91
)
Other income (expense), net
(2
)
 
(3
)
Total other income and (expense)
(87
)
 
(81
)
Earnings Before Income Taxes
325

 
263

Income taxes
124

 
92

Net Income
201

 
171

Dividends on Preferred and Preference Stock
4

 
4

Net Income After Dividends on Preferred and Preference Stock
$
197

 
$
167

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Net Income
$
201

 
$
171

Other comprehensive income (loss):
 
 
 
Qualifying hedges:
 
 
 
Reclassification adjustment for amounts included in net income,
net of tax of $- and $-, respectively
1

 
1

Total other comprehensive income (loss)
1

 
1

Comprehensive Income
$
202

 
$
172

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

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Table of Contents


GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in millions)
Operating Activities:
 
 
 
Net income
$
201

 
$
171

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
239

 
229

Deferred income taxes
59

 
38

Allowance for equity funds used during construction
(6
)
 
(13
)
Retail fuel cost over recovery—long-term
(58
)
 
—

Deferred expenses
31

 
23

Other, net
(27
)
 
10

Changes in certain current assets and liabilities —
 
 
 
-Receivables
40

 
258

-Fossil fuel stock
(4
)
 
(122
)
-Prepaid income taxes
11

 
10

-Other current assets
42

 
(4
)
-Accounts payable
78

 
(62
)
-Accrued taxes
(127
)
 
(206
)
-Accrued compensation
(66
)
 
(80
)
-Retail fuel cost over recovery—short-term
10

 
22

-Other current liabilities
5

 
38

Net cash provided from operating activities
428

 
312

Investing Activities:
 
 
 
Property additions
(419
)
 
(476
)
Investment in restricted cash from pollution control bonds
(18
)
 
—

Nuclear decommissioning trust fund purchases
(205
)
 
(287
)
Nuclear decommissioning trust fund sales
204

 
285

Cost of removal, net of salvage
(17
)
 
(15
)
Change in construction payables, net of joint owner portion
(25
)
 
(203
)
Other investing activities
1

 
15

Net cash used for investing activities
(479
)
 
(681
)
Financing Activities:
 
 
 
Increase in notes payable, net
300

 
99

Proceeds —
 
 
 
Capital contributions from parent company
11

 
9

Pollution control revenue bonds issuances
18

 
—

Senior notes issuances
650

 
750

Redemptions —
 
 
 
Senior notes
(650
)
 
—

Other long-term debt
—

 
(250
)
Payment of preferred and preference stock dividends
(4
)
 
(4
)
Payment of common stock dividends
(227
)
 
(227
)
Other financing activities
(13
)
 
(8
)
Net cash provided from financing activities
85

 
369

Net Change in Cash and Cash Equivalents
34

 
—

Cash and Cash Equivalents at Beginning of Period
45

 
13

Cash and Cash Equivalents at End of Period
$
79

 
$
13

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $3 and $6 capitalized for 2013 and 2012, respectively)
$
72

 
$
58

Income taxes, net
3

 
28

Noncash transactions—accrued property additions at end of period
212

 
178

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

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Table of Contents


GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets
 
At March 31,
2013
 
At December 31,
2012
 
 
(in millions)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
79

 
$
45

Restricted cash and cash equivalents
 
18

 
—

Receivables —
 
 
 
 
Customer accounts receivable
 
500

 
484

Unbilled revenues
 
187

 
217

Joint owner accounts receivable
 
52

 
51

Other accounts and notes receivable
 
53

 
68

Affiliated companies
 
25

 
23

Accumulated provision for uncollectible accounts
 
(6
)
 
(6
)
Fossil fuel stock, at average cost
 
996

 
992

Materials and supplies, at average cost
 
409

 
452

Vacation pay
 
86

 
85

Prepaid income taxes
 
151

 
164

Other regulatory assets, current
 
48

 
72

Other current assets
 
48

 
104

Total current assets
 
2,646

 
2,751

Property, Plant, and Equipment:
 
 
 
 
In service
 
29,462

 
29,244

Less accumulated provision for depreciation
 
10,574

 
10,431

Plant in service, net of depreciation
 
18,888

 
18,813

Other utility plant, net
 
266

 
263

Nuclear fuel, at amortized cost
 
506

 
497

Construction work in progress
 
3,079

 
2,893

Total property, plant, and equipment
 
22,739

 
22,466

Other Property and Investments:
 
 
 
 
Equity investments in unconsolidated subsidiaries
 
46

 
45

Nuclear decommissioning trusts, at fair value
 
723

 
698

Miscellaneous property and investments
 
42

 
44

Total other property and investments
 
811

 
787

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
726

 
733

Other regulatory assets, deferred
 
1,794

 
1,798

Other deferred charges and assets
 
279

 
268

Total deferred charges and other assets
 
2,799

 
2,799

Total Assets
 
$
28,995

 
$
28,803

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


54
Table of Contents


GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity
 
At March 31,
2013
 
At December 31,
2012
 
 
(in millions)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
1,047

 
$
1,680

Notes payable
 
302

 
2

Accounts payable —
 
 
 
 
Affiliated
 
419

 
417

Other
 
503

 
436

Customer deposits
 
241

 
237

Accrued taxes —
 
 
 
 
Accrued income taxes
 
43

 
6

Other accrued taxes
 
96

 
260

Accrued interest
 
113

 
100

Accrued vacation pay
 
60

 
61

Accrued compensation
 
48

 
113

Liabilities from risk management activities
 
17

 
30

Other regulatory liabilities, current
 
56

 
73

Over recovered regulatory clause revenues, current
 
117

 
107

Other current liabilities
 
119

 
146

Total current liabilities
 
3,181

 
3,668

Long-term Debt
 
8,641

 
7,994

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
4,914

 
4,861

Deferred credits related to income taxes
 
113

 
115

Accumulated deferred investment tax credits
 
206

 
208

Employee benefit obligations
 
945

 
950

Asset retirement obligations
 
1,148

 
1,097

Other cost of removal obligations
 
63

 
63

Other deferred credits and liabilities
 
260

 
308

Total deferred credits and other liabilities
 
7,649

 
7,602

Total Liabilities
 
19,471

 
19,264

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
 
5,599

 
5,585

Retained earnings
 
3,267

 
3,297

Accumulated other comprehensive loss
 
(6
)
 
(7
)
Total common stockholder's equity
 
9,258

 
9,273

Total Liabilities and Stockholder's Equity
 
$
28,995

 
$
28,803

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

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


FIRST QUARTER 2013 vs. FIRST QUARTER 2012

OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area 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 Plant Vogtle Units 3 and 4 to increase its generation diversity. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power is scheduled to file its next base rate case by July 1, 2013, which will determine whether the 2010 ARP should be continued, modified, or discontinued.
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. See FUTURE EARNINGS POTENTIAL – "Other Matters" herein for information regarding an explosion at Plant Bowen in April 2013 that is expected to negatively impact Georgia Power's actual performance on its peak season equivalent forced outage rate, one of its key performance indicators, for 2013, as compared to the target.
RESULTS OF OPERATIONS
Net Income
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$30
18.0
Georgia Power's net income after dividends on preferred and preference stock for the first quarter 2013 was $197 million compared to $167 million for the corresponding period in 2012. The increase was primarily due to an increase in retail base revenues as authorized under the 2010 ARP and the NCCR tariff and more favorable weather in the first quarter 2013 as compared to the corresponding period in 2012, partially offset by higher income taxes and an increase in depreciation related to new generating units at Plant McDonough-Atkinson.
Retail Revenues
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$135
8.5
In the first quarter 2013, retail revenues were $1.73 billion compared to $1.59 billion for the corresponding period in 2012.


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


Details of the change to retail revenues were as follows:
 
 
First Quarter
2013
 
 
(in millions)
 
(% change)
Retail – prior year
 
$
1,594

 
 
Estimated change in –
 
 
 
 
Rates and pricing
 
45

 
2.8

Sales growth (decline)
 
2

 
0.1

Weather
 
20

 
1.3

Fuel cost recovery
 
68

 
4.3

Retail – current year
 
$
1,729

 
8.5
%
Revenues associated with changes in rates and pricing increased in the first quarter 2013 when compared to the corresponding period in 2012 primarily due to base tariff increases effective April 2012 and January 1, 2013, as approved by the Georgia PSC, related to placing new generating units at Plant McDonough-Atkinson in service, the financing costs related to the construction of Plant Vogtle Units 3 and 4, and demand-side management costs, partially offset by the pricing effect of increased customer demand.
Revenues attributable to changes in sales increased slightly in the first quarter 2013 when compared to the corresponding period in 2012. Weather-adjusted residential KWH sales increased 0.7%, weather-adjusted commercial KWH sales increased 1.0%, and weather-adjusted industrial KWH sales decreased 3.0% in the first quarter 2013 when compared to the corresponding period in 2012. Decreased demand in the chemicals, paper, and primary metals sectors was the main contributor to the decreases in weather-adjusted industrial KWH sales. In addition, an extra day of sales as a result of the leap year in 2012 negatively impacted KWH sales in all customer classes in 2013.
In the first quarter 2012, Georgia Power began using new actual advanced meter data to compute unbilled revenues. The weather-adjusted KWH sales variances shown above reflect an adjustment to the estimated allocation of Georgia Power's unbilled January 2012 KWH sales among customer classes that is consistent with the actual allocation in 2013. Without this adjustment, first quarter 2013 residential and industrial weather-adjusted KWH sales decreased 1.3% and 3.1%, respectively, as compared to the corresponding period in 2012 and commercial weather-adjusted KWH sales increased 2.8% as compared to the corresponding period in 2012.
Revenues resulting from changes in weather increased in the first quarter 2013 when compared to the corresponding period in 2012 due to more favorable weather in the first quarter 2013 as compared to the corresponding period in 2012.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $68 million in the first quarter 2013 when compared to the corresponding period in 2012 due to increased KWH energy sales and higher fuel costs.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.

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


Fuel and Purchased Power Expenses 
 
 
First Quarter 2013
vs.
First Quarter 2012
 
 
(change in millions)
(% change)
Fuel
 
$
79

18.0

Purchased power — non-affiliates
 
(43
)
(46.2
)
Purchased power — affiliates
 
16

10.1

Total fuel and purchased power expenses
 
$
52

 
In the first quarter 2013, total fuel and purchased power expenses were $744 million compared to $692 million in the corresponding period in 2012. The increase was primarily due to a $62 million increase in the average cost of fuel and purchased power due to higher fuel prices and a $65 million increase in the volume of KWHs generated as a result of higher customer demand, partially offset by a $75 million decrease in the volume of KWHs purchased as the market cost of available energy was higher than Georgia Power-owned generation.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.
Details of Georgia Power's generation and purchased power were as follows:
 
 
First Quarter
2013
 
First Quarter
2012
Total generation (billions of KWHs)
 
15
 
13
Total purchased power (billions of KWHs)
 
6
 
8
Sources of generation (percent) —
 
 
 
 
Coal
 
29
 
42
Nuclear
 
22
 
30
Gas
 
46
 
26
Hydro
 
3
 
2
Cost of fuel, generated (cents per net KWH) —
 
 
 
 
Coal
 
5.28
 
4.67
Nuclear
 
0.90
 
0.86
Gas
 
3.14
 
3.16
Average cost of fuel, generated (cents per net KWH)
 
3.28
 
3.10
Average cost of purchased power (cents per net KWH)(a)
 
4.44
 
3.86
(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 first quarter 2013, fuel expense was $519 million compared to $440 million in the corresponding period in 2012. The increase was primarily due to a 16.8% increase in the volume of KWHs generated as a result of higher KWH demand and a 5.8% increase in the average cost of fuel per KWH generated primarily due to higher coal and nuclear fuel prices.

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Purchased Power – Non-Affiliates
In the first quarter 2013, purchased power expense from non-affiliates was $50 million compared to $93 million in the corresponding period in 2012. The decrease was due to a 68.3% decrease in the volume of KWHs purchased as the cost of Georgia Power-owned generation was lower than the market cost of available energy, partially offset by an increase of 70.8% in the average cost per KWH purchased primarily due to fixed capacity payment provisions in the PPAs.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the first quarter 2013, purchased power expense from affiliates was $175 million compared to $159 million in the corresponding period in 2012. The increase was due to a 16.4% increase in the average cost per KWH purchased, reflecting higher fuel prices, partially offset by a 12.3% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources.
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
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(3)
(0.7)
In the first quarter 2013, other operations and maintenance expenses were $431 million compared to $434 million in the corresponding period in 2012. The decrease was primarily due to a $10 million decrease in fossil generating maintenance due to timing of plant outages and a $2 million decrease in uncollectible account expense, partially offset by a $10 million increase in pension and other employee benefit-related expenses.
Depreciation and Amortization
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$12
6.4
In the first quarter 2013, depreciation and amortization was $200 million compared to $188 million in the corresponding period in 2012. The increase was primarily due to an increase of $23 million in depreciation as a result of additional plant in service primarily due to the completion of Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, partially offset by $9 million in amortization of the regulatory liability previously established for state income tax credits, as authorized by the Georgia PSC. See Note 1 to the financial statements of Georgia Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.

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Taxes Other Than Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$8
9.2
In the first quarter 2013, taxes other than income taxes were $95 million compared to $87 million in the corresponding period in 2012. The increase was due to a $4 million increase in property taxes and a $4 million increase in municipal franchise fees related to higher retail revenues in 2013.
Allowance for Equity Funds Used During Construction
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(7)
(53.8)
In the first quarter 2013, AFUDC equity was $6 million compared to $13 million in the corresponding period in 2012. The decrease was primarily due to the completion of Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively.
Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$32
34.8
In the first quarter 2013, income taxes were $124 million compared to $92 million in the corresponding period in 2012. The increase was primarily due to higher pre-tax earnings, the recognition in 2012 of previously unrecognized tax positions as a result of a settlement with the IRS related to the production activities deduction, and 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 and the successful completion of ongoing construction projects. 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 regional and global economic conditions may impact sales for Georgia Power as 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.
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

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negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for information regarding the EPA's MATS rule and the 2007 State of Georgia Multi-Pollutant Rule.
On April 24, 2013, the EPA published a final reconsideration rule addressing new source standards within the MATS rule. Although the EPA had considered revisions to the startup and shutdown provisions of the MATS rule, a final decision on these provisions was deferred. The ultimate impact of this rulemaking will depend on the outcome of any additional rulemaking and/or legal challenges and, therefore, cannot be determined at this time.
On April 30, 2013, the State of Georgia finalized revisions to the 2007 State of Georgia Multi-Pollutant Rule and a companion rule requiring a 95% reduction in sulfur dioxide emissions from certain coal-fired generating units. The revisions modify the compliance dates under those two rules for units yet to be controlled to synchronize them with the MATS rule compliance deadline. The revisions also allow natural gas to be used as a compliance alternative at Plant Yates as contemplated by the 2013 IRP. The ultimate outcome of these matters cannot be determined at this time. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed revision of the current steam electric effluent guidelines. On April 19, 2013, the EPA signed a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Georgia Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.
PSC Matters
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.
As of March 31, 2013, Georgia Power's fuel cost over recovery balance totaled $182 million and is included in current liabilities and other deferred credits and liabilities on Georgia Power's Condensed Balance Sheet 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 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.

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Integrated Resource Plans
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 " – Integrated Resource Plans" 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; the 2011 IRP; and the 2013 IRP.
On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013. The Georgia PSC is scheduled to vote on all other aspects of the 2013 IRP in July 2013. The ultimate outcome of this matter cannot be determined at this time.
Separately, on April 22, 2013, Georgia Power executed two PPAs to purchase energy from two wind farms with capacity totaling 250 MWs in southwest Oklahoma that will commence in 2016 and end in 2035. In addition, on April 29, 2013, Georgia Power executed a PPA for the purchase of 50 MWs of capacity and energy that will commence in 2015 and end in 2035. These PPAs are subject to Georgia PSC approval and, if approved, will result in contractual obligations of approximately $13 million in 2015, $47 million in 2016, $48 million in 2017, and $1.3 billion thereafter.
Nuclear Construction
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters –Nuclear Construction" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding the construction of Plant Vogtle Units 3 and 4, the eighth Vogtle Construction Monitoring (VCM) report, and pending litigation.
In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects through annual adjustments to an NCCR tariff by including the related CWIP accounts in rate base during the construction period.
The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, and $50 million, effective January 1, 2011, 2012, and 2013, respectively. 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 March 31, 2013, approximately $50 million of these 2009 and 2010 costs remained unamortized in CWIP.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. On February 19, 2013, the Georgia PSC voted to approve Georgia Power's seventh VCM report, including construction capital costs incurred through June 30, 2012 of approximately $2.0 billion. Georgia Power's eighth VCM report requests approval for an additional $0.2 billion of construction capital costs incurred through December 31, 2012. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, the eighth VCM also requests an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately $2.0 billion. The Georgia PSC is expected to vote on the eighth VCM by October 2013.

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In addition, processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document, as amended (DCD), and the combined construction and operating licenses (COLs), including rigorous inspections by Southern Nuclear and the NRC that occur throughout construction. During the fourth quarter 2012, certain details of the rebar design for the Plant Vogtle Unit 3 nuclear island were evaluated for consistency with the DCD and deviations were identified. On February 26, 2013 and March 1, 2013, the NRC approved the two license amendment requests required to conform the rebar design details to NRC requirements and, on March 14, 2013, the placement of basemat structural concrete for the nuclear island of Plant Vogtle Unit 3 was completed. Additional license amendment requests are pending before the NRC. Various design and other issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Owners, the Contractor, or both.
As construction continues, additional delays in the fabrication and assembly of structural modules, the failure of such modules to meet applicable standards, or other issues may further impact project schedule and cost. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4, but also may be resolved through litigation.
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 matters cannot be determined at this time.
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, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, 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) to the Condensed Financial Statements 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 NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011. On March 19, 2013, the NRC issued an order relating to hardened vents for certain classes of containment structures, including the one in use at Plant Hatch. Georgia Power is continuing to analyze the impact of this order. The ultimate outcome of this matter cannot be determined at this time; however, management does not currently anticipate that the compliance costs associated with this order would have a material impact on Georgia Power's financial statements.

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On April 4, 2013, an explosion occurred at Plant Bowen Unit 2 that resulted in substantial damage to the Plant Bowen Unit 2 generator, Plant Bowen's Units 1 and 2 control room and surrounding areas, as well as Plant Bowen's switchyard. The extent of the damage sustained by Plant Bowen Unit 1 is unknown. Plant Bowen Units 1 and 2 (approximately 1,400 MWs) remain offline, pending assessment of the damage and completion of repairs. Georgia Power expects that any material repair costs related to the damage will be covered by property insurance. The ultimate outcome of this matter 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 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, and Pension and Other Postretirement Benefits.
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 March 31, 2013. 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $428 million for the first three months of 2013 compared to $312 million for the corresponding period in 2012. The increase was primarily due to lower fuel inventory additions in 2013. Net cash used for investing activities totaled $479 million compared to $681 million used in the corresponding period in 2012. The decrease was primarily due to higher cash payments for construction expenditures in 2012. Net cash provided from financing activities totaled $85 million for the first three months of 2013 compared to $369 million in the corresponding period in 2012. The decrease is primarily due to additional net issuances of debt in 2012. 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 three months of 2013 include increases of $273 million in total property, plant, and equipment and $314 million in debt, as well as a $164 million decrease in other accrued taxes.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for new generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $1.0 billion will be required through March 31, 2014 to fund maturities of long-term debt.

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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 regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
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 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. The conditional commitment will expire on June 30, 2013, unless further extended by the DOE. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Nuclear Construction" 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. Georgia Power has substantial cash flow from operating activities and access to the capital markets to meet liquidity needs.
At March 31, 2013, Georgia Power had approximately $79 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2013 were as follows:
Expires(a)
 
 
 
Executable Term Loans
 
Due Within One Year
2013
 
2014
 
2016
 
2018
 
Total
 
Unused
 
One Year
 
Two Years
 
Term Out
 
No Term
Out

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

 
$
—

 
$
150

 
$
1,600

 
$
1,750

 
$
1,740

 
$
—

 
$
—

 
$
—

 
$
—

 (a) No credit arrangements expire in 2015 or 2017.

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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.
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 March 31, 2013 was approximately $874 million.
In February 2013, Georgia Power amended its multi-year credit arrangement, which extended the maturity date from 2016 to 2018. In addition, in March 2013, Georgia Power amended certain of its credit arrangements, which extended the maturity dates from 2014 to 2016.
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 company under these arrangements are several and there is no cross affiliate credit support.
These arrangements contain covenants that limit debt levels and 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.
Details of short-term borrowings were as follows:
 
 
Short-term Debt at March 31, 2013(a)
 
Short-term Debt During the Period(a)(b)
 
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
 
(in millions)
 
 
 
(in millions)
 
 
 
(in millions)
Commercial paper
 
$
—

 
—
%
 
$
110

 
0.3
%
 
$
296

Short-term bank debt
 
300

 
0.9
%
 
87

 
0.9
%
 
300

Total
 
$
300

 
0.9
%
 
$
197

 
0.5
%
 
 
(a) Excludes notes payable related to other energy service contracts of $2 million.
(b) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2013.
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

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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 March 31, 2013 were as follows:
 
 
 
Credit Ratings
Maximum Potential
Collateral Requirements
 
(in millions)
At BBB- and/or Baa3
$
65

Below BBB- and/or Baa3
1,298

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 first quarter 2013 has not changed materially compared with the December 31, 2012 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 a result, Georgia Power had no material change in market risk exposure for the first quarter 2013 relative to fuel and electricity prices when compared with the December 31, 2012 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2013 were as follows: 
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(33
)
Contracts realized or settled
 
10

Current period changes(a)
 
8

Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(15
)
(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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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 months ended March 31, 2013 were as follows: 
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
6

Natural gas options
 
12

Total changes
 
$
18

The net hedge volumes of energy-related derivative contracts were as follows: 
 
 
March 31,
2013
December 31,
2012
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
11

12

Commodity – Natural gas options
 
79

93

Total hedge volume
 
90

105

The weighted average swap contract cost above market prices was approximately $0.64 per mmBtu as of March 31, 2013 and $1.09 per mmBtu as of December 31, 2012. The change in option fair value 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 months ended March 31, 2013 and 2012 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, which are all Level 2 of the fair value hierarchy, at March 31, 2013 were as follows: 
 
 
March 31, 2013
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3  
 
 
 
 
(in millions)
 
 
Level 1
 
$
—

 
$
—

 
$
—

Level 2
 
(15
)
 
(11
)
 
(4
)
Level 3
 
—

 
—

 
—

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

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


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.
Financing Activities
In January 2013, Georgia Power's $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013 matured.
In March 2013, Georgia Power entered into three 60-day floating rate bank loans bearing interest based on one-month LIBOR. Each of these short-term loans was for $100 million aggregate principal amount, and the proceeds were used for working capital and other general corporate purposes, including Georgia Power's continuous construction program.
In March 2013, Georgia Power issued $400 million aggregate principal amount of Series 2013A 4.30% Senior Notes due March 15, 2043. Also in March 2013, Georgia Power issued $250 million aggregate principal amount of Series 2013B Floating Rate Senior Notes due March 15, 2016. The proceeds from the sale of the Series 2013A Senior Notes, together with the proceeds from the sale of the Series 2013B Senior Notes, were used to repay at maturity $350 million aggregate principal amount of Georgia Power's Series 2010A Floating Rate Senior Notes due March 15, 2013, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.
In March 2013, the Development Authority of Monroe County issued $17.5 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2013 due April 1, 2043 for the benefit of Georgia Power. The proceeds were used to redeem, in April 2013, $17.5 million aggregate principal amount of Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 1997.
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

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GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Operating Revenues:
 
 
 
Retail revenues
$
259,877

 
$
238,520

Wholesale revenues, non-affiliates
21,208

 
27,118

Wholesale revenues, affiliates
29,455

 
36,364

Other revenues
15,734

 
14,243

Total operating revenues
326,274

 
316,245

Operating Expenses:
 
 
 
Fuel
120,846

 
121,088

Purchased power, non-affiliates
11,135

 
11,225

Purchased power, affiliates
3,312

 
2,513

Other operations and maintenance
78,662

 
75,230

Depreciation and amortization
37,053

 
33,307

Taxes other than income taxes
23,626

 
23,784

Total operating expenses
274,634

 
267,147

Operating Income
51,640

 
49,098

Other Income and (Expense):
 
 
 
Allowance for equity funds used during construction
1,134

 
1,237

Interest expense, net of amounts capitalized
(14,369
)
 
(15,368
)
Other income (expense), net
(976
)
 
(1,009
)
Total other income and (expense)
(14,211
)
 
(15,140
)
Earnings Before Income Taxes
37,429

 
33,958

Income taxes
14,086

 
11,741

Net Income
23,343

 
22,217

Dividends on Preference Stock
1,551

 
1,551

Net Income After Dividends on Preference Stock
$
21,792

 
$
20,666

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Net Income
$
23,343

 
$
22,217

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

 
143

Total other comprehensive income (loss)
143

 
143

Comprehensive Income
$
23,486

 
$
22,360

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 Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Operating Activities:
 
 
 
Net income
$
23,343

 
$
22,217

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
38,794

 
34,844

Deferred income taxes
16,777

 
32,505

Allowance for equity funds used during construction
(1,134
)
 
(1,237
)
Pension, postretirement, and other employee benefits
2,889

 
1,315

Stock based compensation expense
669

 
685

Other, net
2,485

 
5,478

Changes in certain current assets and liabilities —
 
 
 
-Receivables
(2,305
)
 
14,754

-Prepayments
934

 
1,559

-Fossil fuel stock
1,423

 
1,543

-Materials and supplies
(513
)
 
(1,476
)
-Prepaid income taxes
(7,667
)
 
17,324

-Accounts payable
(17,812
)
 
(21,516
)
-Accrued taxes
5,380

 
(1,453
)
-Accrued compensation
(9,451
)
 
(9,190
)
-Over recovered regulatory clause revenues
(10,186
)
 
14,516

-Other current liabilities
6,073

 
5,637

Net cash provided from operating activities
49,699

 
117,505

Investing Activities:
 
 
 
Property additions
(66,696
)
 
(94,879
)
Cost of removal, net of salvage
(3,469
)
 
(9,342
)
Change in construction payables
1,787

 
7,773

Payments pursuant to long-term service agreements
(1,558
)
 
(2,274
)
Other investing activities
243

 
(76
)
Net cash used for investing activities
(69,693
)
 
(98,798
)
Financing Activities:
 
 
 
Increase (decrease) in notes payable, net
5,809

 
(27,338
)
Proceeds —
 
 
 
Common stock issued to parent
40,000

 
40,000

Capital contributions from parent company
556

 
732

Redemptions —
 
 
 
Senior notes
—

 
(16
)
Payment of preference stock dividends
(1,551
)
 
(1,551
)
Payment of common stock dividends
(28,850
)
 
(28,950
)
Other financing activities
(206
)
 
198

Net cash provided from (used for) financing activities
15,758

 
(16,925
)
Net Change in Cash and Cash Equivalents
(4,236
)
 
1,782

Cash and Cash Equivalents at Beginning of Period
32,167

 
17,328

Cash and Cash Equivalents at End of Period
$
27,931

 
$
19,110

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $601 and $493 capitalized for 2013 and 2012, respectively)
$
8,306

 
$
9,352

Income taxes, net
3,886

 
(35,742
)
Noncash transactions — accrued property additions at end of period
22,462

 
28,788

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 BALANCE SHEETS (UNAUDITED)
 
Assets
 
At March 31,
2013
 
At December 31,
2012
 
 
(in thousands)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
27,931

 
$
32,167

Receivables —
 
 
 
 
Customer accounts receivable
 
61,190

 
58,449

Unbilled revenues
 
47,817

 
53,363

Under recovered regulatory clause revenues
 
15,153

 
6,138

Other accounts and notes receivable
 
13,019

 
11,859

Affiliated companies
 
8,709

 
13,624

Accumulated provision for uncollectible accounts
 
(1,261
)
 
(1,490
)
Fossil fuel stock, at average cost
 
152,287

 
153,710

Materials and supplies, at average cost
 
53,877

 
53,365

Other regulatory assets, current
 
20,475

 
30,576

Prepaid expenses
 
63,697

 
62,877

Other current assets
 
10,682

 
2,690

Total current assets
 
473,576

 
477,328

Property, Plant, and Equipment:
 
 
 
 
In service
 
4,261,604

 
4,260,844

Less accumulated provision for depreciation
 
1,170,499

 
1,168,055

Plant in service, net of depreciation
 
3,091,105

 
3,092,789

Construction work in progress
 
178,025

 
136,062

Total property, plant, and equipment
 
3,269,130

 
3,228,851

Other Property and Investments
 
15,494

 
15,737

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
50,664

 
50,139

Other regulatory assets, deferred
 
373,289

 
372,294

Other deferred charges and assets
 
33,531

 
33,053

Total deferred charges and other assets
 
457,484

 
455,486

Total Assets
 
$
4,215,684

 
$
4,177,402

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 BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity
 
At March 31,
2013
 
At December 31,
2012
 
 
(in thousands)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
60,000

 
$
60,000

Notes payable
 
132,811

 
127,002

Accounts payable —
 
 
 
 
Affiliated
 
60,226

 
66,161

Other
 
44,953

 
54,551

Customer deposits
 
34,950

 
34,749

Accrued taxes —
 
 
 
 
Accrued income taxes
 
4,094

 
45

Other accrued taxes
 
12,302

 
7,036

Accrued interest
 
18,098

 
12,364

Accrued compensation
 
5,514

 
14,966

Other regulatory liabilities, current
 
18,903

 
25,887

Liabilities from risk management activities
 
7,782

 
16,529

Other current liabilities
 
20,429

 
19,930

Total current liabilities
 
420,062

 
439,220

Long-term Debt
 
1,186,022

 
1,185,870

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
660,762

 
648,952

Accumulated deferred investment tax credits
 
5,070

 
5,408

Employee benefit obligations
 
127,254

 
126,871

Other cost of removal obligations
 
218,801

 
213,413

Other regulatory liabilities, deferred
 
50,027

 
47,863

Deferred capacity expense
 
148,213

 
137,568

Other deferred credits and liabilities
 
86,514

 
93,497

Total deferred credits and other liabilities
 
1,296,641

 
1,273,572

Total Liabilities
 
2,902,725

 
2,898,662

Preference Stock
 
97,998

 
97,998

Common Stockholder's Equity:
 
 
 
 
Common stock, without par value—
 
 
 
 
Authorized — 20,000,000 shares
 
 
 
 
Outstanding — March 31, 2013: 4,942,717 shares
 
 
 
 
                — December 31, 2012: 4,542,717 shares
 
433,060

 
393,060

Paid-in capital
 
548,933

 
547,798

Retained earnings
 
234,406

 
241,465

Accumulated other comprehensive loss
 
(1,438
)
 
(1,581
)
Total common stockholder's equity
 
1,214,961

 
1,180,742

Total Liabilities and Stockholder's Equity
 
$
4,215,684

 
$
4,177,402

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

FIRST QUARTER 2013 vs. FIRST QUARTER 2012

OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area 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, restoration following major storms, and fuel. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
On May 9, 2013, in accordance with the Florida Administrative Code Rules, Gulf Power notified the Florida PSC of Gulf Power's intent to file for an increase in Gulf Power's base rates. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Base Rate Case" herein for additional information.
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
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$1.1
5.4
Gulf Power's net income after dividends on preference stock for the first quarter 2013 was $21.8 million compared to $20.7 million for the corresponding period in 2012. The increase was primarily due to higher retail base revenues resulting from the retail base rate increase effective April 2012 and more favorable weather in the first quarter 2013 compared to the corresponding period in 2012. The increase was partially offset by a decrease in customer usage in 2013, lower wholesale capacity revenues from non-affiliates in 2013, and an increase in depreciation in 2013.
Retail Revenues
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$21.4
9.0
In the first quarter 2013, retail revenues were $259.9 million compared to $238.5 million for the corresponding period in 2012.

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

Details of the change to retail revenues were as follows:
 
 
First Quarter 2013
 
 
(in millions)
 
(% change)
Retail – prior year
 
$
238.5

 
 
Estimated change in –
 
 
 
 
Rates and pricing
 
5.8

 
2.4

Sales growth (decline)
 
(2.7
)
 
(1.1
)
Weather
 
3.6

 
1.5

Fuel and other cost recovery
 
14.7

 
6.2

Retail – current year
 
$
259.9

 
9.0

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 first quarter 2013 when compared to the corresponding period in 2012 primarily due to an increase in retail base revenues resulting from the retail base rate increase effective April 2012.
Revenues attributable to changes in sales decreased in the first quarter 2013 when compared to the corresponding period in 2012. Weather-adjusted KWH energy sales to residential and commercial customers decreased 2.7% and 1.1%, respectively, primarily due to a decrease in customer usage. KWH energy sales to industrial customers decreased 2.8% primarily due to increased customer co-generation.
Revenues attributable to changes in weather increased in the first quarter 2013 when compared to the corresponding period in 2012 due to more favorable weather in the first quarter 2013.
Fuel and other cost recovery revenues increased in the first quarter 2013 when compared to the corresponding period in 2012 primarily due to higher revenues associated with recoverable fuel costs for generation and purchased power costs generally due to higher natural gas prices. 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
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(5.9)
(21.8)
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 sales to 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.

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

In the first quarter 2013, wholesale revenues from non-affiliates were $21.2 million compared to $27.1 million for the corresponding period in 2012. The decrease primarily resulted from lower energy revenues related to a 47.0% decrease in KWH sales as a result of less energy scheduled by unit power customers to serve their loads. The decrease was also due to a 12.6% decrease in revenues primarily related to certain contract provisions that allow for cost adjustments related to compliance with new environmental requirements.
Wholesale Revenues – Affiliates
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(6.9)
(19.0)
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.
In the first quarter 2013, wholesale revenues from sales to affiliates were $29.5 million compared to $36.4 million for the corresponding period in 2012. The decrease was primarily due to lower energy revenues related to a 32.4% decrease in KWH sales resulting from lower Gulf Power generation dispatched to serve affiliated companies' demand in the first quarter 2013 compared to the corresponding period in 2012. This decrease was partially offset by a 19.9% increase in the price of energy in the first quarter 2013.
Fuel and Purchased Power Expenses
 
 
First Quarter 2013
vs.
First Quarter 2012
 
 
(change in millions)
(% change)
Fuel
 
$
(0.2
)
(0.2
)
Purchased power – non-affiliates
 
(0.1
)
(0.8
)
Purchased power – affiliates
 
0.8

31.8

Total fuel and purchased power expenses
 
$
0.5

 
In the first quarter 2013, total fuel and purchased power expenses were $135.3 million compared to $134.8 million for the corresponding period in 2012. The increase in fuel and purchased power expenses was due to a $21.5 million increase in the average cost of fuel and purchased power, partially offset by a $21.0 million decrease related to the volume of KWHs generated and purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel 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.

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

Details of Gulf Power's generation and purchased power were as follows: 
 
 
First Quarter
2013
 
First Quarter
2012
Total generation (millions of KWHs)
 
1,861

 
2,341

Total purchased power (millions of KWHs)
 
1,663

 
1,750

Sources of generation (percent) –
 
 
 
 
Coal
 
52

 
53

Gas
 
48

 
47

Cost of fuel, generated (cents per net KWH) –
 
 
 
 
Coal
 
4.68

 
4.29

Gas
 
3.72

 
3.44

Average cost of fuel, generated (cents per net KWH)
 
4.22

 
3.89

Average cost of purchased power (cents per net KWH)(a)
 
3.42

 
2.50

(a) Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is
generated by the provider.
Fuel
In the first quarter 2013, fuel expense was $120.9 million compared to $121.1 million for the corresponding period in 2012. The decrease was not material.
Purchased Power – Non-Affiliates
In the first quarter 2013, purchased power expense from non-affiliates was $11.1 million compared to $11.2 million for the corresponding period in 2012. The decrease was not material.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the first quarter 2013, purchased power expense from affiliates was $3.3 million compared to $2.5 million for the corresponding period in 2012. The increase reflects an increase of $1.3 million in energy costs, offset by a decrease of $0.5 million in capacity costs. The increase in energy costs was due to an increase in the volume of KWHs purchased and a higher 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.
Other Operations and Maintenance Expenses
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$3.4
4.6
In the first quarter 2013, other operations and maintenance expenses were $78.6 million compared to $75.2 million for the corresponding period in 2012. The increase was primarily due to increases of $1.5 million for transmission service related to a third party PPA, $1.3 million for labor and benefit-related expenses, and $1.3 million in marketing programs. The increased expense from transmission service did not have a significant impact on earnings since the expense was offset by purchased power capacity revenues through Gulf Power's purchased power capacity recovery clause. The increased expense from marketing programs did not have a significant impact on earnings

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

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 – Purchased Power Capacity Recovery" and "– Energy Conservation Cost Recovery" herein for additional information.
Depreciation and Amortization
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$3.7
11.2
In the first quarter 2013, depreciation and amortization was $37.0 million compared to $33.3 million for the corresponding period in 2012. The increase was primarily due to the addition of environmental control projects at generation facilities and other net additions to transmission and distribution facilities.
Interest Expense, Net of Amounts Capitalized
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(1.0)
(6.5)
In the first quarter 2013, interest expense, net of amounts capitalized was $14.4 million compared to $15.4 million for the corresponding period in 2012. The decrease was primarily due to lower interest rates on pollution control bonds, senior notes, and customer deposits.
Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$2.4
20.0
In the first quarter 2013, income taxes were $14.1 million compared to $11.7 million for the corresponding period in 2012. The increase was primarily due to higher pre-tax earnings and the recognition in 2012 of previously unrecognized tax benefits.
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 regional and global economic conditions may impact sales for Gulf Power as 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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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 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.
Gulf Power has determined it is not economical to add the environmental controls at Plant Scholz necessary to comply with the MATS rule and that coal-fired generation at Plant Scholz will cease by April 2015. The plant is scheduled to be fully depreciated by April 2015.
Environmental Statutes and Regulations
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 information regarding the EPA's MATS rule. On April 24, 2013, the EPA published a final reconsideration rule addressing new source standards within the MATS rule. Although the EPA had considered revisions to the startup and shutdown provisions of the MATS rule, a final decision on these provisions was deferred. The ultimate impact of this rulemaking will depend on the outcome of any additional rulemaking and/or legal challenges and, therefore, 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 regarding the EPA's proposed revision of the current steam electric effluent guidelines. On April 19, 2013, the EPA signed a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Gulf Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.
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 May 9, 2013, in accordance with the Florida Administrative Code Rules, Gulf Power notified the Florida PSC of Gulf Power's intent to file for an increase in Gulf Power's base rates, not sooner than July 8, 2013 (60 days after the notification) and not later than July 22, 2013. Gulf Power is proposing the projected 12 months ending December 31, 2014 as the test year for the anticipated rate case filing. The proposed test year is a calendar year that corresponds to Gulf Power's fiscal year and largely corresponds with the first fiscal period that new, permanent rates could be in effect. Gulf Power currently estimates that an increase in annual revenues between $75 million and $80 million will be requested. The ultimate outcome of this matter cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – 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 – Cost Recovery Clauses – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
Over recovered fuel costs at March 31, 2013 totaled $5.1 million compared to $17.1 million at December 31, 2012. 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 – Cost Recovery Clauses – 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 – Cost Recovery Clauses – Purchased Power Capacity Recovery," respectively, in Item 8 of the Form 10-K for additional information.
At March 31, 2013, the over recovered purchased power capacity costs totaled $1.8 million, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein. At December 31, 2012, the under recovered purchased power capacity costs totaled $0.8 million, which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.
Environmental Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Environmental Cost Recovery" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
Under recovered environmental costs at March 31, 2013 totaled $8.9 million compared to $1.9 million at December 31, 2012. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.
Energy Conservation Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Energy Conservation Cost Recovery" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.
Under recovered energy conservation costs at March 31, 2013 totaled $3.0 million compared to $0.8 million at December 31, 2012. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.
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

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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, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, 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) to the Condensed Financial Statements 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, 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 March 31, 2013. 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.
Net cash provided from operating activities totaled $49.7 million for the first three months of 2013 compared to $117.5 million for the corresponding period in 2012. The $67.8 million decrease was primarily due to decreases in deferred income taxes related to bonus depreciation, prepaid income taxes, and the recovery of fuel costs. Net cash used for investing activities totaled $69.7 million in the first three months of 2013 primarily due to property additions to utility plant and costs of removal. Net cash provided from financing activities totaled $15.8 million for the first three months of 2013. This was primarily due to issuances of common stock and an increase in notes payable, partially offset by payment of common stock dividends. 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 three months of 2013 include a net increase of $40.3 million in property, plant, and equipment, primarily due to the addition of environmental control projects at generation facilities and other net additions to transmission and distribution facilities and an increase in common stock due to the issuance of common stock to Southern Company for $40 million.

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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 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 statutes and 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. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $60 million will be required through March 31, 2014 to fund maturities of long-term debt.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Gulf Power plans to obtain the funds required 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.
At March 31, 2013, Gulf Power had approximately $27.9 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2013 were as follows:
Expires(a)
 
 
 
 
 
Executable Term
Loans
 
Due Within One
Year
2013
 
2014
 
2016
 
Total
 
Unused
 
    One
    Year
 
Two    
Years    
 
    Term
    Out
 
No Term
Out
(in millions)
 
(in millions)
 
(in millions)
 
(in millions)
$
45

 
$
60

 
$
165

 
$
270

 
$
270

 
$
45

 
$
—

 
$
45

 
$
30

(a)
No credit arrangements expire in 2015.
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.
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 March 31, 2013 was approximately $69 million. In addition, Gulf Power has substantial cash flows from operating activities and access to the capital markets to meet liquidity needs.
In March 2013, Gulf Power amended several credit arrangements, which extended the maturity dates from 2014 to 2016. Gulf Power also amended a $35 million credit arrangement, which reduced the amount to $30 million and

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

extended the maturity date from 2013 to 2014. Subsequent to March 31, 2013, Gulf Power entered into a new credit arrangement for $5 million with a maturity date of 2014.
Most of these arrangements contain covenants that limit debt levels and 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.
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 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
March 31, 2013
 
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
 
$
130

 
0.3
%
 
$
114

 
0.3
%
 
$
130

(a)
Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2013.
Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.
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 March 31, 2013 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
 
(in millions)
At BBB- and/or Baa3
$
117

Below BBB- and/or Baa3
484

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 and the variable rate pollution control revenue bond markets.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the first quarter 2013 has not changed materially compared with the December 31, 2012 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. To mitigate residual risks relative to natural gas purchases, 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 a result, Gulf Power had no material change in market risk exposure for the first quarter 2013 when compared with the December 31, 2012 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2013 were as follows:
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(23
)
Contracts realized or settled
 
5

Current period changes(a)
 
16

Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(2
)
(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 months ended March 31, 2013 were as follows: 
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
21

Natural gas options
 
—

Total changes
 
$
21

The net hedge volumes of energy-related derivative contracts were as follows: 
 
 
March 31,
2013
December 31,
2012
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
70

71

Commodity – Natural gas options
 
—

—

Total hedge volume
 
70

71

The weighted average swap contract cost above market prices was approximately $0.02 per mmBtu as of March 31, 2013 and $0.32 per mmBtu as of December 31, 2012. The change in option fair value 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2013 and 2012 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, which are all Level 2 of the fair value hierarchy, at March 31, 2013 were as follows:
 
 
March 31, 2013    
Fair Value Measurements    
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(2
)
 
1

 
(2
)
 
(1
)
Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(2
)
 
$
1

 
$
(2
)
 
$
(1
)
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 February 2013, Gulf Power issued to Southern Company 400,000 shares of Gulf Power's common stock 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 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
CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Operating Revenues:
 
 
 
Retail revenues
$
168,310

 
$
166,271

Wholesale revenues, non-affiliates
65,109

 
54,231

Wholesale revenues, affiliates
8,341

 
4,040

Other revenues
4,174

 
4,172

Total operating revenues
245,934

 
228,714

Operating Expenses:
 
 
 
Fuel
104,564

 
88,619

Purchased power, non-affiliates
1,367

 
1,943

Purchased power, affiliates
9,689

 
8,860

Other operations and maintenance
54,812

 
54,895

Depreciation and amortization
23,233

 
22,481

Taxes other than income taxes
19,417

 
21,703

Estimated loss on Kemper IGCC
462,000

 
—

Total operating expenses
675,082

 
198,501

Operating Income (Loss)
(429,148
)
 
30,213

Other Income and (Expense):
 
 
 
Allowance for equity funds used during construction
26,074

 
11,827

Interest expense, net of amounts capitalized
(10,409
)
 
(7,805
)
Other income (expense), net
(1,547
)
 
(122
)
Total other income and (expense)
14,118

 
3,900

Earnings (Loss) Before Income Taxes
(415,030
)
 
34,113

Income taxes (benefit)
(169,142
)
 
8,425

Net Income (Loss)
(245,888
)
 
25,688

Dividends on Preferred Stock
433

 
433

Net Income (Loss) After Dividends on Preferred Stock
$
(246,321
)
 
$
25,255

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Net Income (Loss)
$
(245,888
)
 
$
25,688

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

 
(478
)
Reclassification adjustment for amounts included in net income, net of tax of $131 and $16, respectively
212

 
26

Total other comprehensive income (loss)
212

 
(452
)
Comprehensive Income (Loss)
$
(245,676
)
 
$
25,236

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 Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Operating Activities:
 
 
 
Net income (loss)
$
(245,888
)
 
$
25,688

Adjustments to reconcile net income (loss)
  to net cash provided from (used for) operating activities —
 
 
 
Depreciation and amortization, total
21,692

 
21,931

Deferred income taxes
(174,082
)
 
(1,210
)
Investment tax credits received
—

 
13,974

Allowance for equity funds used during construction
(26,074
)
 
(11,827
)
Pension, postretirement, and other employee benefits
2,926

 
2,268

Hedge settlements
—

 
(15,983
)
Stock based compensation expense
1,033

 
957

Regulatory assets associated with Kemper IGCC
(6,843
)
 
(2,243
)
Estimated loss on Kemper IGCC
462,000

 
—

Other, net
(628
)
 
1,117

Changes in certain current assets and liabilities —
 
 
 
-Receivables
(5,226
)
 
14,536

-Fossil fuel stock
8,415

 
(16,188
)
-Materials and supplies
(4,744
)
 
(538
)
-Prepaid income taxes
1,573

 
4,168

-Other current assets
(2,389
)
 
(4,357
)
-Accounts payable
(13,783
)
 
(11,558
)
-Accrued taxes
(45,429
)
 
(31,434
)
-Accrued interest
6,570

 
9,514

-Accrued compensation
(10,247
)
 
(10,803
)
-Over recovered regulatory clause revenues
2,996

 
12,627

-Other current liabilities
2,971

 
(35
)
Net cash provided from (used for) operating activities
(25,157
)
 
604

Investing Activities:
 
 
 
Property additions
(369,313
)
 
(370,923
)
Cost of removal, net of salvage
(902
)
 
(1,149
)
Construction payables
23,150

 
30,080

Capital grant proceeds
1,784

 
1,816

Other investing activities
(7,145
)
 
(4,207
)
Net cash used for investing activities
(352,426
)
 
(344,383
)
Financing Activities:
 
 
 
Proceeds —
 
 
 
Capital contributions from parent company
100,552

 
150,735

Bonds-Other
15,814

 
—

Senior notes issuances
—

 
400,000

Interest-bearing refundable deposit related to asset sale
—

 
150,000

Other long-term debt issuances
350,000

 
—

Redemptions —
 
 
 
Capital leases
—

 
(377
)
Other long-term debt
—

 
(75,000
)
Payment of preferred stock dividends
(433
)
 
(433
)
Payment of common stock dividends
(44,190
)
 
(26,700
)
Other financing activities
(1,409
)
 
715

Net cash provided from financing activities
420,334

 
598,940

Net Change in Cash and Cash Equivalents
42,751

 
255,161

Cash and Cash Equivalents at Beginning of Period
145,008

 
211,585

Cash and Cash Equivalents at End of Period
$
187,759

 
$
466,746

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (paid $16,001 and $5,965, net of $11,141 and $6,565
capitalized for 2013 and 2012, respectively)
$
4,860

 
$
—

Income taxes, net
(25
)
 
(11,994
)
Noncash transactions—accrued property additions at end of period
238,013

 
165,982

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 March 31,
2013
 
At December 31,
2012
 
 
(in thousands)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
187,759

 
$
145,008

Receivables —
 
 
 
 
Customer accounts receivable
 
32,288

 
29,561

Unbilled revenues
 
33,324

 
32,688

Other accounts and notes receivable
 
5,851

 
7,517

Affiliated companies
 
31,475

 
27,160

Accumulated provision for uncollectible accounts
 
(298
)
 
(373
)
Fossil fuel stock, at average cost
 
167,963

 
176,378

Materials and supplies, at average cost
 
39,004

 
34,260

Other regulatory assets, current
 
53,058

 
55,302

Prepaid income taxes
 
173,818

 
129,835

Other current assets
 
33,268

 
17,170

Total current assets
 
757,510

 
654,506

Property, Plant, and Equipment:
 
 
 
 
In service
 
3,073,750

 
3,036,159

Less accumulated provision for depreciation
 
1,083,639

 
1,065,474

Plant in service, net of depreciation
 
1,990,111

 
1,970,685

Construction work in progress
 
2,289,256

 
2,393,145

Total property, plant, and equipment
 
4,279,367

 
4,363,830

Other Property and Investments
 
4,836

 
4,887

Deferred Charges and Other Assets:
 
 
 
 
Deferred charges related to income taxes
 
81,855

 
71,869

Other regulatory assets, deferred
 
244,585

 
236,225

Other deferred charges and assets
 
36,943

 
42,304

Total deferred charges and other assets
 
363,383

 
350,398

Total Assets
 
$
5,405,096

 
$
5,373,621

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 March 31,
2013
 
At December 31,
2012
 
 
(in thousands)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
342,285

 
$
276,471

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

 
150,000

Accounts payable —
 
 
 
 
Affiliated
 
53,795

 
54,769

Other
 
273,305

 
262,992

Customer deposits
 
14,415

 
14,202

Accrued taxes —
 
 
 
 
Accrued income taxes
 
4,750

 
2,339

Other accrued taxes
 
21,951

 
69,376

Accrued interest
 
36,946

 
30,376

Accrued compensation
 
5,459

 
15,706

Other regulatory liabilities, current
 
10,863

 
5,376

Over recovered regulatory clause liabilities
 
80,333

 
77,338

Liabilities from risk management activities
 
6,671

 
13,116

Other current liabilities
 
19,200

 
18,766

Total current liabilities
 
1,019,973

 
990,827

Long-term Debt
 
1,869,056

 
1,564,462

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
80,676

 
244,958

Deferred credits related to income taxes
 
9,676

 
10,106

Accumulated deferred investment tax credits
 
420,678

 
370,554

Employee benefit obligations
 
157,542

 
157,421

Other cost of removal obligations
 
148,190

 
143,461

Other regulatory liabilities, deferred
 
56,457

 
56,984

Other deferred credits and liabilities
 
49,842

 
52,860

Total deferred credits and other liabilities
 
923,061

 
1,036,344

Total Liabilities
 
3,812,090

 
3,591,633

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
 
1,502,836

 
1,401,520

Retained earnings
 
28,199

 
318,710

Accumulated other comprehensive loss
 
(8,500
)
 
(8,713
)
Total common stockholder's equity
 
1,560,226

 
1,749,208

Total Liabilities and Stockholder's Equity
 
$
5,405,096

 
$
5,373,621

The accompanying notes as they relate to Mississippi 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

FIRST QUARTER 2013 vs. FIRST QUARTER 2012

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 March 5, 2013, the Mississippi PSC issued an order with respect to Mississippi Power's request for an increase in rates which allows Mississippi Power an annual rate designed to collect $125 million for 2013, with such amounts to be recorded as a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service, increasing to $156 million in 2014, which represents a 15% and 3% increase in retail rates for 2013 and 2014, respectively. Also on March 5, 2013, the Mississippi PSC approved a $15.3 million, or 1.9%, increase in annual rates under Mississippi Power's PEP and a $35.5 million, or 4.7%, decrease in annual rates due to an annual adjustment to the retail fuel cost recovery factor, with all new rates effective March 19, 2013.
On April 23, 2013, Mississippi Power revised its cost estimate for the Kemper IGCC to approximately $3.42 billion, net of the DOE Grants and certain exceptions to the $2.88 billion cost cap established by the Mississippi PSC. For additional information on the Kemper IGCC, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 of the Form 10-K/A, Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
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/A.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS
Net Income (Loss)
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(271.6)
N/M
N/M - Not meaningful
Mississippi Power's net loss after dividends on preferred stock for the first quarter 2013 was $246.3 million compared to net income after dividends on preferred stock of $25.3 million for the corresponding period in 2012. The decrease was primarily related to a revision of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and the cost of the lignite mine and equipment, the cost of the carbon dioxide (CO2) pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The loss was partially offset by an increase in AFUDC equity primarily related to the construction of the Kemper IGCC and an increase in territorial base revenues primarily due to a wholesale base rate increase effective April 1, 2012.
Retail Revenues
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$2.0
1.2
In the first quarter 2013, retail revenues were $168.3 million compared to $166.3 million for the corresponding period in 2012.
Details of the change to retail revenues were as follows:
 
 
First Quarter
2013
 
 
(in millions)
(% change)
Retail – prior year
 
$
166.3

 
Estimated change in –
 
 
 
Rates and pricing
 
(3.7
)
(2.2
)
Sales growth (decline)
 
(2.9
)
(1.7
)
Weather
 
3.5

2.1

Fuel and other cost recovery
 
5.1

3.1

Retail – current year
 
$
168.3

1.3
 %
Revenues associated with changes in rates and pricing decreased in the first quarter 2013 when compared to the corresponding period in 2012 primarily due to a $4.7 million accrual for a retail refund related to the annual PEP lookback filing. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Performance Evaluation Plan" herein for additional information.
Revenues attributable to changes in sales decreased in the first quarter 2013 when compared to the corresponding period in 2012. Weather-adjusted KWH energy sales to residential and commercial customers decreased 1.8% and 1.4%, respectively, when compared to the corresponding period in 2012 due to decreased economic activity. KWH energy sales to industrial customers decreased 4.1% due to decreased production for several larger customers.

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Revenues attributable to changes in weather increased in the first quarter 2013 when compared to the corresponding period in 2012 primarily due to more favorable weather in the first quarter 2013.
Fuel and other cost recovery revenues increased in the first quarter 2013 when compared to the corresponding period in 2012 primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
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
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$10.9
20.1
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's 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 first quarter 2013, wholesale revenues from non-affiliates were $65.1 million compared to $54.2 million for the corresponding period in 2012. The increase was due to a $6.3 million increase in revenues primarily resulting from a wholesale base rate increase effective April 1, 2012 and a $4.6 million increase in energy revenues, of which $2.4 million was associated with higher fuel prices and $2.2 million was associated with an increase in KWH sales due to higher demand resulting from more favorable weather in the first quarter 2013 compared to the corresponding period in 2012.
Wholesale Revenues – Affiliates
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$4.3
N/M
N/M - Not meaningful
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases 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 first quarter 2013, wholesale revenues from affiliates were $8.3 million compared to $4.0 million for the corresponding period in 2012. The increase was primarily due to a $4.4 million increase in energy revenues, of which $3.0 million was associated with an increase in KWH sales and $1.4 million was associated with higher energy prices.

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Fuel and Purchased Power Expenses
 
 
First Quarter 2013
vs.
First Quarter 2012
 
 
(change in millions)
 
(% change)
Fuel
 
$
16.0

 
18.0

Purchased power – non-affiliates
 
(0.6
)
 
(29.6
)
Purchased power – affiliates
 
0.8

 
9.4

Total fuel and purchased power expenses
 
$
16.2

 
 
In the first quarter 2013, total fuel and purchased power expenses were $115.6 million compared to $99.4 million for the corresponding period in 2012. The increase was primarily due to a $9.4 million increase in the total volume of KWHs generated and purchased and a $6.8 million increase in the cost of fuel and purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.
Details of Mississippi Power's generation and purchased power were as follows:
 
 
First Quarter
2013
 
First Quarter
2012
Total generation (millions of KWHs)
 
3,204
 
2,982
Total purchased power (millions of KWHs)
 
393
 
447
Sources of generation (percent) –
 
 
 
 
Coal
 
27
 
21
Gas
 
73
 
79
Cost of fuel, generated (cents per net KWH) –
 
 
 
 
Coal
 
5.03
 
4.77
Gas
 
2.98
 
2.83
Average cost of fuel, generated (cents per net KWH)
 
3.57
 
3.29
Average cost of purchased power (cents per net KWH)
 
2.82
 
2.42
Fuel
In the first quarter 2013, fuel expense was $104.6 million compared to $88.6 million for the corresponding period in 2012. The increase was primarily due to an 8.5% increase in the average cost of fuel per KWH generated and an 8.6% increase in the volume of KWHs generated resulting from higher energy demand in the first quarter 2013 compared to the corresponding period in 2012.
Purchased Power – Non-Affiliates
In the first quarter 2013, purchased power expense from non-affiliates was $1.3 million compared to $1.9 million for the corresponding period in 2012. The decrease was primarily the result of a 20.0% decrease in the volume of KWHs purchased and a 12.3% decrease in the average cost per KWH purchased.
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.

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Purchased Power – Affiliates
In the first quarter 2013, purchased power expense from affiliates was $9.7 million compared to $8.9 million for the corresponding period in 2012. The increase was primarily due to a 21.8% increase in the average cost per KWH purchased, partially offset by a 9.9% decrease 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
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(0.1)
(0.2)
In the first quarter 2013, other operations and maintenance expenses were $54.8 million compared to $54.9 million for the corresponding period in 2012. The decrease was primarily due to a $2.1 million decrease in generation maintenance expenses related to scheduled outages and a $0.8 million decrease in distribution expenses related to overhead line maintenance and vegetation management costs. These decreases were partially offset by a $3.1 million increase in administrative and general expenses.
Taxes Other Than Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(2.3)
(10.5)
In the first quarter 2013, taxes other than income taxes were $19.4 million compared to $21.7 million for the corresponding period in 2012. The decrease was primarily due to a $1.8 million decrease in ad valorem taxes and a $0.4 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.
Estimated Loss on Kemper IGCC
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$462.0
N/M
N/M - Not meaningful
In the first quarter 2013, an estimated probable loss on the Kemper IGCC of $462.0 million was recorded to reflect a revision of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and the Cost Cap Exceptions. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$14.3
120.5

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In the first quarter 2013, AFUDC equity was $26.1 million compared to $11.8 million for the corresponding period in 2012. The increase was 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/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$2.6
33.4
In the first quarter 2013, interest expense, net of amounts capitalized was $10.4 million compared to $7.8 million for the corresponding period in 2012. Capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC in the first quarter 2013 was $11.1 million compared to $6.5 million for the corresponding period in 2012. The increase was primarily due to a $5.7 million increase in interest expense associated with issuances of new long-term debt in March 2012, August 2012, November 2012, January 2013, and March 2013 and a $3.0 million increase in interest expense resulting from the receipt of a $150 million deposit from SMEPA in March 2012 related to its pending purchase of an undivided interest in the Kemper IGCC. These increases were partially offset by a $4.6 million increase in capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC and a $1.5 million decrease in interest expense associated with the redemption of long-term debt in 2012.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(177.5)
N/M
N/M - Not meaningful
In the first quarter 2013, income taxes were $(169.1) million compared to $8.4 million for the corresponding period in 2012. The decrease was due to the reduction in pre-tax earnings (loss) related to the estimated probable loss for the Kemper IGCC.
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 and the successful completion of ongoing construction projects, including the Kemper IGCC. 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 regional and global economic conditions may impact sales for Mississippi Power as 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K/A.
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/A for additional information.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Mississippi Power in Item 7 of the Form 10-K/A for information regarding the EPA's MATS rule. On April 24, 2013, the EPA published a final reconsideration rule addressing new source standards within the MATS rule. Although the EPA had considered revisions to the startup and shutdown provisions of the MATS rule, a final decision on these provisions was deferred. The ultimate impact of this rulemaking will depend on the outcome of any additional rulemaking and/or legal challenges and, therefore, 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/A for additional information regarding the EPA's proposed revision of the current steam electric effluent guidelines. On April 19, 2013, the EPA signed a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Mississippi Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" 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/A and Note (B) to the Condensed Financial Statement under "FERC Matters" herein for additional information.
In 2011, Mississippi Power filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff. In March 2012, Mississippi Power entered into a settlement agreement with its wholesale customers which provided that base revenues would increase by approximately $22.6 million over a 12-month period with revised rates effective for services rendered beginning April 1, 2012. In March 2012, the FERC approved a motion to place interim rates into effect beginning in May 2012. In September 2012, Mississippi Power, with its wholesale customers, filed a final settlement agreement with the FERC. In November 2012, the settlement judge certified the settlement agreement to the FERC with the recommendation that it be approved. The FERC has not yet approved the settlement agreement.

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On April 1, 2013, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the MRA cost-based electric tariff. The 2013 settlement agreement provides that base rates under the MRA cost-based electric tariff will increase by approximately $24.2 million over a 12-month period, with revised rates effective for services rendered beginning April 1, 2013. If the 2013 settlement agreement is approved by the FERC, the amount of base rate revenues to be received in 2013 from the agreed upon increase will be approximately $18.0 million.
The ultimate outcome of these matters cannot be determined at this time.
PSC Matters
General
In August 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. On March 14, 2013, the Mississippi Public Utilities Staff (MPUS) filed with the Mississippi PSC its report on 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/A for additional information regarding Mississippi Power's base rates.
On January 18, 2013, Mississippi Power filed its annual PEP filing for 2013, which indicated a rate increase of 1.990%, or $15.8 million, annually. On March 4, 2013, Mississippi Power and the MPUS filed a joint stipulation which revised the annual PEP filing for 2013 to reflect the removal of certain costs related to unresolved matters that are currently under review. On March 5, 2013 the revised annual PEP filing for 2013 was approved by the Mississippi PSC, which resulted in a rate increase of 1.925%, or $15.3 million, annually, with the new rates effective March 19, 2013. Mississippi Power may be entitled to $3.3 million in additional revenues in 2013 as a result of the late implementation of the 2013 PEP rate increase.
On March 15, 2013, Mississippi Power submitted its annual PEP lookback filing for 2012, which indicated a refund due to customers of $4.7 million, which was accrued in retail revenues. On May 1, 2013, the MPUS contested the filing.
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/A for information on Mississippi Power's annual environmental filing with the Mississippi PSC.
In April 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. In May 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 March 31, 2013, total project expenditures were $183.2 million, with Mississippi Power's portion being $91.6 million. The ultimate outcome of this matter cannot be determined at this time.

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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/A for information regarding Mississippi Power's fuel cost recovery.
On January 18, 2013, in compliance with Mississippi Power's filing requirement, Mississippi Power requested an annual adjustment of the retail fuel cost recovery factor in an amount equal to a decrease of 4.7%, or $35.5 million, of total 2012 retail revenue. The Mississippi PSC approved the retail fuel cost recovery factor on March 5, 2013, with the new rates effective March 19, 2013.
At March 31, 2013, the amount of over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $60.9 million compared to $56.6 million at December 31, 2012. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At March 31, 2013, the amount of over recovered wholesale MRA and MB fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $18.1 million and $1.7 million, respectively, compared to $19.0 million and $2.1 million, respectively, at December 31, 2012. In addition, at each of March 31, 2013 and December 31, 2012, the amount of under recovered MRA emissions allowance cost included on Mississippi Power's Condensed Balance Sheets herein was $0.4 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, changes in the billing factor have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.
Ad Valorem Tax Adjustment
On March 27, 2013, Mississippi Power filed its annual Ad Valorem Tax Adjustment factor filing for 2013, which requested an annual rate increase of 0.9%, or $7.1 million, due to an increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4.
The ultimate outcome of this matter cannot be determined at this time.
See RESULTS OF OPERATIONS – "Taxes Other Than Income Taxes" of Mississippi Power in Item 7 of the Form 10-K/A for additional information.
Storm Damage Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Storm Damage Cost Recovery" of Mississippi Power in Item 7 and 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/A for information regarding Mississippi Power's storm damage cost recovery. 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 March 31, 2013, the balance in the storm reserve was $57.2 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/A for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Project Approval
In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC (2010 MPSC Order) located in Kemper County, Mississippi. The Sierra Club filed an appeal of the Mississippi PSC's issuance of the CPCN and, in March 2012, the Mississippi Supreme Court reversed the decision of the Chancery Court upholding the 2010 MPSC Order and remanded the matter to the Mississippi PSC. The

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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. In April 2012, the Mississippi PSC issued a detailed order (2012 MPSC Order) confirming the CPCN for the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. In December 2012, the Chancery Court affirmed the 2012 MPSC Order which confirmed the issuance of the CPCN for the Kemper IGCC. On January 8, 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.
The Kemper IGCC is currently under construction and will utilize an integrated coal gasification combined cycle technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC that is scheduled to begin operations in June 2013. In connection with the Kemper IGCC, Mississippi Power also is constructing and plans to operate approximately 61 miles of CO2 pipeline infrastructure. The Kemper IGCC and the CO2 pipeline are scheduled to be placed in-service in May 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO2 Pipeline Facilities" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO2 Pipeline Facilities" in Item 8 of the Form 10-K/A for additional information regarding the lignite mine and the CO2 pipeline.
The ultimate outcome of the CPCN challenge cannot be determined at this time.
Kemper IGCC Cost Estimate
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC Order was $2.4 billion, net of $245 million of DOE Grants, the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions as contemplated in the Settlement Agreement (described below) and the 2012 MPSC Order, which includes change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers, relative to the original proposal for the CPCN) (Cost Cap Exceptions). Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.
On April 23, 2013, Mississippi Power revised its cost estimate for the Kemper IGCC to approximately $3.42 billion, net of the DOE Grants and the Cost Cap Exceptions. Estimated amounts of the Cost Cap Exceptions include $245 million for the lignite mine and equipment, $132 million for the CO2 pipeline facilities, $324 million of AFUDC, and $102 million of other general exceptions. The revised cost estimate reflects additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, and productivity decreases. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for amounts subject to the Cost Cap Exceptions. Accordingly, Mississippi Power reflected a pre-tax charge to income for this estimated probable loss of $462.0 million ($285.3 million after tax) in the first quarter 2013. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC."
Mississippi Power's analysis of the estimated cost to complete the Kemper IGCC will be ongoing throughout the construction period. It is possible that Mississippi Power could experience further cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors 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, delays associated with start-up activities, and/or unforeseen engineering problems. In subsequent periods, any changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap will be reflected in Mississippi Power's statements of income and these changes could be material.

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As of March 31, 2013, Mississippi Power had spent a total of $2.88 billion on the Kemper IGCC, excluding the estimated probable loss. These costs include $2.41 billion for the portion of the Kemper IGCC subject to the construction cost cap, $188.9 million for the lignite mine and equipment, $84.4 million for the CO2 pipeline facilities, $156.4 million of AFUDC, and $43.1 million of other costs, including certain general exceptions and certain regulatory assets. Of this total, $2.29 billion was included in CWIP (which is net of the DOE Grants and an estimated probable loss of $540 million), $43.4 million in other regulatory assets, $3.8 million in other deferred charges and assets on Mississippi Power's Condensed Balance Sheet herein, and $1.0 million was previously expensed. Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings.
The ultimate outcome of these matters cannot be determined at this time.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" for additional information regarding Mississippi Power's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Baseload Act" herein for additional information.
On January 24, 2013, Mississippi Power entered into a settlement agreement (Settlement Agreement) with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC. Under the Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions as well as any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. Mississippi Power intends to finance (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and the Cost Cap Exceptions, (2) the accrued AFUDC, and (3) exceptions not provided for in the Seven-Year Rate Plan (discussed below) through securitization as provided in State of Mississippi legislation. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective after the Kemper IGCC is placed in service and following completion of the Mississippi PSC's final prudence review of costs for the Kemper IGCC.
Under the terms of the Settlement Agreement, Mississippi Power and the Mississippi PSC agreed to follow certain regulatory procedures and schedules for resolving the cost recovery matters related to the Kemper IGCC. These procedures and schedules include the following: (1) Mississippi Power's filing on January 25, 2013 of a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service; (2) the Mississippi PSC's decision on that matter on March 5, 2013 as described below; (3) Mississippi Power's collaboration with the MPUS to file with the Mississippi PSC within three months of the Settlement Agreement a rate recovery plan for the Kemper IGCC for the first seven years of its operation, along with a proposed revenue requirement under such plan for 2014 through 2020 (Seven-Year Rate Plan) (which was made on February 26, 2013 and updated on March 22, 2013 as described below); (4) the Mississippi PSC's decision on the Seven-Year Rate Plan within four months of that filing (which is now expected to occur in the fall of 2013); (5) Mississippi Power's agreement to limit the portion of prudently-incurred Kemper IGCC costs to be included in rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, excluding AFUDC, provided that this limitation will not prevent Mississippi Power from securing alternate financing to recover any prudently-incurred Kemper IGCC costs, including plant costs above the $2.4 billion certificated cost estimate and AFUDC, not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement; and (6) the Mississippi PSC's completion of its prudence review of the Kemper IGCC costs incurred through 2012 within six

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months of the Settlement Agreement, an additional prudence review upon considering the Seven-Year Rate Plan for costs incurred through the most recent reporting period, and a final prudence review of the remaining project costs within six months of the Kemper IGCC's in-service date. The Settlement Agreement provides that Mississippi Power may terminate the agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization was enacted into law on February 26, 2013. Mississippi Power is currently working with the Mississippi PSC and the MPUS to implement the procedural schedules set forth in the Settlement Agreement and variations to the schedule are likely.
On March 5, 2013, the Mississippi PSC issued an order (2013 Kemper IGCC Order) approving a 15% increase in retail rates effective on March 19, 2013, and an additional 3% increase in retail rates effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. All amounts collected through April 2014, which are expected to total $126 million, will be recorded as a regulatory liability to be used to mitigate rate impacts beginning in May 2014 when the Kemper IGCC is expected to be placed in service. On March 21, 2013, a legal challenge to the 2013 Kemper IGCC Order was filed with the Mississippi Supreme Court.
Because the 2013 Kemper IGCC Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act described below, Mississippi Power continues to record AFUDC on the Kemper IGCC during the construction period. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power's rate plans filed pursuant to the Settlement Agreement contemplate the continued accrual of AFUDC through the May 2014 expected in-service date.
On March 22, 2013, Mississippi Power, in compliance with the 2013 Kemper IGCC Order, filed a revision to the Seven-Year Rate Plan with the Mississippi PSC for the Kemper IGCC for 2014 through 2020, the first seven years of operation of the Kemper IGCC. The Seven-Year Rate Plan, which contemplates Mississippi Power's sale of a 15% undivided ownership interest in the Kemper IGCC, proposes recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 Kemper IGCC Order, which increased rates beginning on March 19, 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the April 2014 regulatory liability balance to be used to mitigate rate impacts from the expected in-service date of May 2014 through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan filing, Mississippi Power proposes annual rate recovery to remain the same from 2014 through 2020. While it is the intent of Mississippi Power for the actual revenue requirement to equal the proposed revenue requirement, Mississippi Power proposes that the annual differences through 2020 for certain items contemplated in the Seven-Year Rate Plan will be deferred, subject to accrual of carrying costs, and the cumulative balance will be reviewed at the end of the term of the Settlement Agreement by the Mississippi PSC to determine the disposition of any potential remaining deferred balance.
The revenue requirements set forth in Mississippi Power's Seven-Year Rate Plan described above assume, among other things, the Kemper IGCC will be placed in service in May 2014, the sale of a 15% undivided interest in the Kemper IGCC to SMEPA will be completed as described herein, Mississippi Power's receipt of the benefits relating to tax credits described herein, and recovery of the Cost Cap Exceptions described herein.
The ultimate outcome of these matters, including the determinations of prudency and the specific manner of recovery of costs relating to the Kemper IGCC, is subject to further regulatory actions and cannot be determined at this time.
Proposed Sale of Undivided Interest to SMEPA
In 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 February 2012, the Mississippi PSC approved the sale

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and transfer of 17.5% of the Kemper IGCC to SMEPA. In June 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. On December 31, 2012, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2013.
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. In September 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.
In March 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 Sheets herein and as financing proceeds in Mississippi Power's Condensed Statements of Cash Flows herein.
The ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi and is designed to enhance the Mississippi PSC's authority to facilitate development and construction of base load generation in the State of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of the legal challenges to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.
Tax Incentives
The IRS has allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Mississippi Power's 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 March 31, 2013, Mississippi Power had received or accrued tax benefits totaling $412 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. As a result of bonus tax depreciation on certain assets placed, or to be placed, in service in 2012 and 2013, and the subsequent reduction in federal taxable income, Mississippi Power estimates that it will not be able to utilize $178.8 million of these tax credits until after March 31, 2014. IRS guidelines allow these unused tax credits to be carried forward for 20 years from the date received, if not utilized before then. In October 2012, Mississippi

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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 as described above. In addition, all or a portion of the tax credits will be subject to recapture if Mississippi Power fails to satisfy the in-service date requirements and CO2 capture requirements described above.
On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and 50% bonus depreciation for property to be placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is expected to apply to the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.
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, property damage, and other claims for damages alleged to have been caused by CO2 and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, 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) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A, 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.
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/A. 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/A for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.
Estimated Construction Costs for the Kemper IGCC
Subsequent to the filing of Mississippi Power's Annual Report on Form 10-K for the year ended December 31, 2012, Mississippi Power revised its cost estimate to complete construction of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and the Cost Cap Exceptions. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any Kemper IGCC construction costs that exceed

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the $2.88 billion cost cap, except for amounts subject to the Cost Cap Exceptions and net of the DOE Grants. As a result, Mississippi Power recorded a pretax charge of $78 million and $462 million in 2012 and the first quarter 2013, respectively. In subsequent periods, any changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap will be reflected in Mississippi Power's statements of income and these changes could be material. Mississippi Power's analysis will be ongoing throughout the construction period. It is possible that Mississippi Power could experience further cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors 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, delays associated with start-up activities, and/or unforeseen engineering problems. Given the significant judgment involved in estimating the future costs to complete construction, schedule, and the ultimate rate recoverability for the Kemper IGCC, schedule, and ultimate recoverability for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers the future total construction costs for the Kemper IGCC to be a critical accounting estimate. See 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/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
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/A for additional information. Mississippi Power's financial condition remained stable at March 31, 2013. 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 used for operating activities totaled $25.2 million for the first three months of 2013, a decrease of $25.8 million as compared to the corresponding period in 2012. The decrease in cash provided from operating activities is primarily due to a decrease in investment tax credits related to the Kemper IGCC, a decrease in accounts receivable, a decrease in accrued taxes, and a decrease in regulatory clause revenues due to an increase in fuel costs, partially offset by an increase in fossil fuel stock and an increase due to hedges settled in 2012. Net cash used for investing activities totaled $352.4 million for the first three months of 2013 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $420.3 million for the first three months of 2013 primarily due to the issuances of bank 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 three months of 2013 include a decrease in total property, plant, and equipment of $84.5 million, a decrease in accumulated deferred income taxes of $164.3 million, and a decrease in total common stockholder's equity of $189.0 million primarily due to the estimated probable loss on the Kemper IGCC. The decrease in retained earnings was partially offset by an increase in paid-in capital of $101.3 million primarily due to $100.0 million of capital contributions from Southern Company. Securities due within one year and long-term debt increased $370.4 million primarily due to the issuance of $350.0 million of bank notes and $15.8 million of revenue bonds. Prepaid income taxes and accumulated deferred investment tax credits increased $44.0 million and $50.1 million, respectively, primarily due to the Kemper IGCC investment tax credit. Other accrued taxes decreased $47.4 million primarily due to the payment of ad valorem taxes.

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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 Mississippi Power in Item 7 of the Form 10-K/A for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $342.3 million will be required through March 31, 2014 to fund maturities of long-term debt.
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information on the construction of the Kemper IGCC. The construction program of Mississippi Power is currently estimated to include a base level investment of $1.2 billion, $638 million, and $255 million for 2013, 2014, and 2015, respectively. Included in these estimated amounts are expenditures related to construction of the Kemper IGCC of $913 million and $358 million in 2013 and 2014, respectively, which are net of SMEPA's 15% proposed ownership share of the Kemper IGCC, which reflects costs of approximately $492 million and $28 million in 2013 and 2014, respectively. The estimated share for SMEPA in 2013 reflects estimated construction costs relating to SMEPA's proposed ownership interest to be incurred through December 31, 2013 (including construction costs for all prior years relating to its proposed ownership interest).
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 regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environment compliance programs; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Kemper IGCC Cost Estimate" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Cost Estimate" herein for a discussion of factors that may impact the projected cost and/or schedule of the Kemper IGCC. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Except as described herein, 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. In January 2013, Mississippi Power received $100 million in capital contributions from Southern Company. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Mississippi Power in Item 7 of the Form 10-K/A for additional information.
Mississippi Power has received $245.3 million in DOE CCPI2 grant funds that have been 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. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

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Mississippi Power's current liabilities frequently exceed current assets because of the continued use of short-term obligations 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 March 31, 2013, Mississippi Power had approximately $187.8 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2013 were as follows: 
Expires(a)
 
 
Executable Term
Loans
 
Due Within One
Year
2013
 
2014
 
2016
 
Total
 
Unused
 
    One
    Year

 
Two    
Years    

 
    Term
    Out

 
No Term
Out

(in millions)
(in millions)
 
(in millions)
 
(in millions)
$
110

 
$
25

 
$
165

 
$
300

 
$
300

 
$
25

 
$
40

 
$
65

 
$
70

(a)No credit arrangements expire in 2015.
See Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K/A and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
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 March 31, 2013 was approximately $40 million.
In March 2013, Mississippi Power amended certain of its credit arrangements, which extended the maturity dates from 2014 to 2016 and revised the definition of debt to exclude securitized debt relating to the Kemper IGCC for purposes of calculating the debt covenant under these credit arrangements. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
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.
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 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
March 31, 2013
 
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
 
$
—

 
—
%
 
$
15

 
0.2
%
 
$
139

(a)
Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2013.
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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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 March 31, 2013, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $268 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.
In March 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 for 2012 and 9.962% per annum at March 31, 2013, 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.
Market Price Risk
Mississippi Power's market risk exposure relative to interest rate changes for the first quarter 2013 has not changed materially compared with the December 31, 2012 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 exchange rates, 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 a result, Mississippi Power had no material change in market risk exposure for the first quarter 2013 when compared with the December 31, 2012 reporting period.
The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2013 were as follows:
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
(17
)
Contracts realized or settled
 
4

Current period changes(a)
 
8

Contracts outstanding at the end of the period, assets (liabilities), net
 
$
(5
)
(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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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 ended March 31, 2013 were as follows: 
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Natural gas swaps
 
$
12

Natural gas options
 
—

Total changes
 
$
12

The net hedge volumes of energy-related derivative contracts were as follows:
 
 
 
March 31,
2013
December 31, 2012
 
 
mmBtu Volume
 
 
(in millions)
Commodity – Natural gas swaps
 
36

38

Commodity – Natural gas options
 
—

—

Total hedge volume
 
36

38

The weighted average swap contract cost above market prices was approximately $0.13 per mmBtu as of March 31, 2013 and $0.44 per mmBtu as of December 31, 2012. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The costs associated with natural gas hedges are recovered through Mississippi Power's energy cost management clauses (ECM).
At March 31, 2013 and December 31, 2012, substantially all of Mississippi Power's energy-related derivative contracts were designated as regulatory hedges and are related to Mississippi Power's fuel-hedging program. Therefore, 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 ECM.
Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2013 and 2012 for energy-related derivative contracts that are not hedges were not material.
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, which are all Level 2 of the fair value hierarchy, at March 31, 2013 were as follows:
 
 
 
 
March 31, 2013
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
(5
)
 
(3
)
 
(2
)
 
—

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
(5
)
 
$
(3
)
 
$
(2
)
 
$
—

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"

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and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In November 2012, Mississippi Power entered into a 366-day $100 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR. The first advance in the amount of $50 million was made in November 2012. In January 2013, the second advance in the amount of $50 million was made. The proceeds of the loan were used for working capital and for other general corporate purposes, including Mississippi Power's continuous construction program.
In March 2013, Mississippi Power entered into four two-year floating rate bank loans bearing interest based on one-month LIBOR. These term loans were for $50 million, $75 million, $75 million, and $100 million aggregate principal amounts, and proceeds were used for working capital and other general corporate purposes, including Mississippi Power's continuous construction program.
In March 2013, the Mississippi Business Finance Corporation (MBFC) issued $15.8 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A. 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 the Series 2012A bonds will be used for this same purpose. See Note 6 to the financial statements of Mississippi Power under "Other Revenue Bonds" in Item 8 of the Form 10-K/A for additional information.
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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Operating Revenues:
 
 
 
Wholesale revenues, non-affiliates
$
223,429

 
$
140,557

Wholesale revenues, affiliates
78,191

 
111,788

Other revenues
1,327

 
1,336

Total operating revenues
302,947

 
253,681

Operating Expenses:
 
 
 
Fuel
119,372

 
89,078

Purchased power, non-affiliates
14,573

 
20,650

Purchased power, affiliates
7,865

 
2,340

Other operations and maintenance
50,950

 
48,389

Depreciation and amortization
40,160

 
31,913

Taxes other than income taxes
5,354

 
4,968

Total operating expenses
238,274


197,338

Operating Income
64,673

 
56,343

Other Income and (Expense):
 
 
 
Interest expense, net of amounts capitalized
(20,394
)
 
(13,642
)
Other income (expense), net
(257
)
 
30

Total other income and (expense)
(20,651
)
 
(13,612
)
Earnings Before Income Taxes
44,022

 
42,731

Income taxes
14,830

 
13,415

Net Income
$
29,192

 
$
29,316

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Net Income
$
29,192

 
$
29,316

Other comprehensive income (loss):
 
 
 
Qualifying hedges:
 
 
 
Changes in fair value, net of tax of $- and $(173), respectively
—

 
(274
)
Reclassification adjustment for amounts included in net income,
net of tax of $1,045 and $956, respectively
1,634

 
1,510

Total other comprehensive income (loss)
1,634

 
1,236

Comprehensive Income
$
30,826

 
$
30,552

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
For the Three Months
Ended March 31,
 
2013
 
2012
 
(in thousands)
Operating Activities:
 
 
 
Net income
$
29,192

 
$
29,316

Adjustments to reconcile net income to net cash provided from operating activities —
 
 
 
Depreciation and amortization, total
42,790

 
34,887

Deferred income taxes
13,587

 
9,917

Investment tax credits
(493
)
 
(3,900
)
Deferred revenues
(20,432
)
 
(16,686
)
Mark-to-market adjustments
(2,746
)
 
6,467

Other, net
2,979

 
1,326

Changes in certain current assets and liabilities —
 
 
 
-Receivables
11,743

 
12,400

-Fossil fuel stock
1,840

 
(755
)
-Materials and supplies
(1,546
)
 
(1,167
)
-Prepaid income taxes
1,600

 
(5,105
)
-Other current assets
1,324

 
(2,083
)
-Accounts payable
(6,933
)
 
(14,590
)
-Accrued taxes
4,155

 
4,375

-Accrued interest
(10,841
)
 
(10,172
)
-Other current liabilities
(314
)
 
(2
)
Net cash provided from operating activities
65,905

 
44,228

Investing Activities:
 
 
 
Property additions
(58,553
)
 
(32,450
)
Change in construction payables
3,704

 
(999
)
Payments pursuant to long-term service agreements
(11,741
)
 
(11,415
)
Other investing activities
(224
)
 
(2,848
)
Net cash used for investing activities
(66,814
)
 
(47,712
)
Financing Activities:
 
 
 
Increase in notes payable, net
76,985

 
20,165

Proceeds — 
 
 
 
Capital contributions
1,033

 
1,219

Other long-term debt
1,717

 
—

Repayments — Other long-term debt
(220
)
 
(150
)
Payment of common stock dividends
(32,280
)
 
(31,750
)
Other financing activities
678

 
25

Net cash provided from (used for) financing activities
47,913

 
(10,491
)
Net Change in Cash and Cash Equivalents
47,004

 
(13,975
)
Cash and Cash Equivalents at Beginning of Period
28,592

 
16,943

Cash and Cash Equivalents at End of Period
$
75,596

 
$
2,968

Supplemental Cash Flow Information:
 
 
 
Cash paid (received) during the period for —
 
 
 
Interest (net of $- and $6,556 capitalized for 2013 and 2012, respectively)
$
28,120

 
$
20,966

Income taxes, net
(179
)
 
10,820

Noncash transactions — accrued property additions at end of period
8,907

 
31,591

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 March 31,
2013
 
At December 31,
2012
 
 
(in thousands)
Current Assets:
 
 
 
 
Cash and cash equivalents
 
$
75,596

 
$
28,592

Receivables —
 
 
 
 
Customer accounts receivable
 
64,391

 
62,857

Other accounts receivable
 
2,164

 
3,135

Affiliated companies
 
26,252

 
38,269

Fossil fuel stock, at average cost
 
19,776

 
21,616

Materials and supplies, at average cost
 
49,943

 
46,370

Prepaid service agreements—current
 
104,424

 
80,629

Prepaid income taxes
 
11,696

 
4,498

Other prepaid expenses
 
4,318

 
5,637

Assets from risk management activities
 
2,916

 
375

Total current assets
 
361,476

 
291,978

Property, Plant, and Equipment:
 
 
 
 
In service
 
4,032,559

 
4,059,839

Less accumulated provision for depreciation
 
808,958

 
786,620

Plant in service, net of depreciation
 
3,223,601

 
3,273,219

Construction work in progress
 
80,502

 
24,835

Total property, plant, and equipment
 
3,304,103

 
3,298,054

Other Property and Investments:
 
 
 
 
Goodwill
 
1,839

 
1,839

Other intangible assets, net of amortization of $3,759 and $3,141 at
  March 31, 2013 and December 31, 2012, respectively
 
45,360

 
45,979

Total other property and investments
 
47,199

 
47,818

Deferred Charges and Other Assets:
 
 
 
 
Prepaid long-term service agreements
 
96,121

 
100,921

Other deferred charges and assets — affiliated
 
6,692

 
3,468

Other deferred charges and assets — non-affiliated
 
42,675

 
37,688

Total deferred charges and other assets
 
145,488

 
142,077

Total Assets
 
$
3,858,266

 
$
3,779,927

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 March 31,
2013
 
At December 31,
2012
 
 
(in thousands)
Current Liabilities:
 
 
 
 
Securities due within one year
 
$
98

 
$
259

Notes payable — non-affiliated
 
147,953

 
70,968

Accounts payable —
 
 
 
 
Affiliated
 
66,864

 
65,832

Other
 
22,197

 
26,204

Accrued taxes —
 
 
 
 
Accrued income taxes
 
1,224

 
87

Other accrued taxes
 
6,915

 
3,031

Accrued interest
 
11,433

 
22,259

Liabilities from risk management activities
 
590

 
669

Other current liabilities
 
7,734

 
8,263

Total current liabilities
 
265,008

 
197,572

Long-term Debt
 
1,307,762

 
1,306,099

Deferred Credits and Other Liabilities:
 
 
 
 
Accumulated deferred income taxes
 
564,301

 
550,685

Investment tax credits
 
174,471

 
167,130

Deferred capacity revenues — affiliated
 
6,835

 
19,514

Other deferred credits and liabilities — affiliated
 
2,384

 
2,638

Other deferred credits and liabilities — non-affiliated
 
5,880

 
5,863

Total deferred credits and other liabilities
 
753,871

 
745,830

Total Liabilities
 
2,326,641

 
2,249,501

Redeemable Noncontrolling Interest
 
9,689

 
8,069

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

 
—

Paid-in capital
 
1,028,581

 
1,027,548

Retained earnings
 
492,497

 
495,585

Accumulated other comprehensive income (loss)
 
858

 
(776
)
Total common stockholder's equity
 
1,521,936

 
1,522,357

Total Liabilities and Stockholder's Equity
 
$
3,858,266

 
$
3,779,927

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

FIRST QUARTER 2013 vs. FIRST QUARTER 2012

OVERVIEW
Southern Power and its subsidiaries construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based rates 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, on April 23, 2013 Southern Power and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Campo Verde Solar, LLC (Campo Verde). Campo Verde is constructing a 139-MW solar facility in Southern California that is expected to begin commercial operation in the fourth quarter 2013. The output of the plant is contracted under a 20-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities. See Note (I) to the Condensed Financial Statements 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 delivered. Net income is the primary measure of Southern Power's financial performance.
RESULTS OF OPERATIONS
Net Income
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(0.1)
(0.4)
Southern Power's net income for the first quarter 2013 was $29.2 million compared to $29.3 million for the corresponding period in 2012. The decrease was primarily due to increases in depreciation, interest expense, other operations and maintenance expenses, and income taxes, partially offset by an increase in capacity revenues due to an increase in total MWs of capacity under long-term contracts, primarily related to the Plant Nacogdoches contract which began in June 2012.
Wholesale Revenues – Non-Affiliates
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$82.8
59.0
Wholesale revenues from 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 first quarter 2013 were $223.4 million compared to $140.6 million for the corresponding period in 2012. The increase was primarily due to a $61.4 million increase in energy sales, reflecting a 33.4% increase in the average price of energy and a 51.9% increase in KWH sales. The increase in

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

revenue was also due to a $21.4 million increase in capacity revenue primarily 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
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$(33.6)
(30.1)
Wholesale revenues from sales to affiliated companies 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 first quarter 2013 were $78.2 million compared to $111.8 million for the corresponding period in 2012. The decrease was primarily the result of a $31.6 million decrease in energy sales under the IIC, reflecting a 54.6% decrease in KWH sales, partially offset by a 24.6% increase in the average price of energy.
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.
Fuel and Purchased Power Expenses
 
 
First Quarter 2013
vs.
First Quarter 2012
 
 
(change in millions)
(% change)
Fuel
 
$30.3
34.0
Purchased power – non-affiliates
 
(6.1)
(29.4)
Purchased power – affiliates
 
5.5
236.1
Total fuel and purchased power expenses
 
$29.7
 
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 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 first quarter 2013, total fuel and purchased power expenses were $141.8 million compared to $112.1 million for the corresponding period in 2012. Fuel and purchased power expenses increased $33.0 million due to a 33.3% increase in the average cost of fuel and a 17.8% increase in the average cost of purchased power. The increase was partially offset by a $3.2 million decrease associated with a 1.8% net decrease in the volume of KWHs generated and purchased.
In the first quarter 2013, fuel expense was $119.4 million compared to $89.1 million for the corresponding period in 2012. The increase was due to a $29.6 million increase associated with the average cost of fuel per KWH generated and a $0.7 million increase associated with the volume of KWHs generated.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2013, purchased power expense was $22.4 million compared to $23.0 million for the corresponding period in 2012. The decrease was due to a $3.9 million decrease associated with the volume of KWHs purchased, partially offset by a $3.4 million increase associated with the cost of purchased power.
Other Operations and Maintenance Expenses
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$2.6
5.3
In the first quarter 2013, other operations and maintenance expenses were $51.0 million compared to $48.4 million for the corresponding period in 2012. The increase was primarily due to operating costs associated with Plant Nacogdoches placed in service in June 2012, Plant Apex placed in service in July 2012, Plant Granville placed in service in October 2012, and Plant Cleveland placed in service in December 2012.
Depreciation and Amortization
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$8.3
25.8
In the first quarter 2013, depreciation and amortization was $40.2 million compared to $31.9 million for the corresponding period in 2012. The increase was primarily due to an increase in plant in service, including the additions of Plants Nacogdoches, Apex, Granville, and Cleveland.
Interest Expense, Net of Amounts Capitalized
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$6.8
49.5
In the first quarter 2013, interest expense, net of amounts capitalized was $20.4 million compared to $13.6 million for the corresponding period in 2012. The increase was primarily due to a decrease in capitalized interest resulting from the completion of Plants Nacogdoches and Cleveland in June 2012 and December 2012, respectively.
Income Taxes
First Quarter 2013 vs. First Quarter 2012
(change in millions)
(% change)
$1.4
10.5
In the first quarter 2013, income taxes were $14.8 million compared to $13.4 million for the corresponding period in 2012. The increase was primarily due to a $2.2 million benefit received in 2012 related to prior year tax adjustments and a $0.6 million increase associated with higher pre-tax earnings, partially offset by a $1.7 million decrease related to an increase in the amount of tax benefit recognized from investment tax credits (ITCs) compared to the first quarter 2012.

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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 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. 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.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed revision of the current steam electric effluent guidelines. On April 19, 2013, the EPA signed a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Southern Power's facilities, which could result in capital expenditures and compliance costs. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Income Tax Matters
Investment Tax Credits
In 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA included renewable energy incentives. Southern Power has recognized ITCs under the renewable energy incentives related to Plants Nacogdoches, Cimarron, Apex, Granville, and Spectrum, which have had a material impact on cash flows and net income. On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several renewable energy incentives through 2013, including extending ITCs for biomass projects which begin construction before January 1, 2014.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Acquisitions
Campo Verde Solar, LLC Acquisition
On April 23, 2013, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Campo Verde from First Solar, Inc., the developer of the project. Campo Verde is constructing a 139-MW solar photovoltaic facility in Southern California. The solar facility is expected to begin commercial operation in the fourth quarter 2013. The output of the plant is contracted under a 20-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy, that is expected to begin in the fourth quarter 2013. See Note (I) to the Condensed Financial Statements herein for additional information.
Construction Projects
Spectrum Nevada Solar, LLC Acquisition
In September 2012, Southern Power and TRE, through STR, 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 mid-2013. Construction costs incurred through March 31, 2013 were $62.8 million. The total estimated cost of the project is expected to be approximately $118.0 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.
On April 23, 2013, a subsidiary of Southern Power assumed a PPA with San Diego Gas & Electric Company in connection with the acquisition of Campo Verde. The solar facility is expected to begin commercial operation in the fourth quarter 2013.
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, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, 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) to the Condensed Financial Statements 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.

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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 Investment Tax Credits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at March 31, 2013. 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 $65.9 million for the first three months of 2013, an increase of $21.7 million as compared to the first three months of 2012. The increase in cash provided from operating activities was primarily due to the timing of payments resulting in a smaller increase in prepaid income tax and a smaller reduction in accounts payable compared to the first quarter 2012. Net cash used for investing activities totaled $66.8 million for the first three months of 2013 primarily due to expenditures related to the construction of Plant Spectrum and payments pursuant to long-term service agreements. Net cash provided from financing activities totaled $47.9 million for the first three months of 2013 primarily due to an increase in notes payable, partially offset by 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 asset changes in the balance sheet for the first three months of 2013 include a $47.0 million increase in cash due to the timing of cash transactions; a $12.0 million decrease in accounts receivable from affiliated companies primarily due to lower energy sales under the IIC; a $23.8 million increase in prepaid service agreements-current due to the timing of plant outages; and a $55.7 million increase in CWIP primarily due to expenditures on Plant Spectrum.
Significant liability and stockholder's equity changes in the balance sheet for the first three months of 2013 include a $77.0 million increase in notes payable to non-affiliates due to the timing of cash transactions; a $10.8 million decrease in accrued interest due to scheduled debt service; a $13.6 million increase in accumulated deferred income taxes primarily due to bonus depreciation; and a $12.7 million decrease in deferred capacity revenues-affiliated due to seasonality.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. There are no requirements through March 31, 2014 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

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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 March 31, 2013 cash and cash equivalents of approximately $75.6 million and a committed credit facility of $500 million (Facility). In February 2013, Southern Power amended the Facility, which extended the maturity date from 2016 to 2018. 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.
Details of short-term borrowings were as follows: 
 
 
Short-term Debt at
March 31, 2013
 
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
 
$
148

 
0.4
%
 
$
44

 
0.4
%
 
$
148

(a)
Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2013.
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.

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The maximum potential collateral requirements under these contracts at March 31, 2013 were as follows:
 
Credit Ratings
Maximum Potential
Collateral Requirements
 
(in millions)
At BBB and Baa2
$
9

At BBB- and/or Baa3
467

Below BBB- and/or Baa3
1,203

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.
Southern Power's market risk exposure relative to interest rate changes for the first quarter 2013 has not changed materially compared with the December 31, 2012 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 months ended March 31, 2013 were as follows:
 
 
First Quarter
2013
Changes
 
 
Fair Value
 
 
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
 
$
0.8

Contracts realized or settled
 
0.2

Current period changes(a)
 
2.6

Contracts outstanding at the end of the period, assets (liabilities), net
 
$
3.6

(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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The change in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2013 was an increase of $2.8 million which is 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:
 
 
March 31,
2013
December 31,
2012
Power – net purchased or (sold)
 
 
 
MWHs (in thousands)
 
(52.8
)
—

Weighted average contract cost per MWH above (below) market prices (in dollars)
 
$
3.58

$
—

Natural gas net purchased
 
 
 
Commodity – million mmBtu
 
5.2

5.0

Commodity – weighted average contract cost per mmBtu above (below) market prices (in dollars)
 
$
(0.57
)
$
(0.02
)
The net 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
 
March 31,
2013
December 31,
2012

 
(in millions)
Cash flow hedges
 
$
—

$
—

Not designated
 
3.6

0.8

Total fair value
 
$
3.6

$
0.8

Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are initially deferred in AOCI 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 Southern Power's statements of income as incurred.
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 Power's statements of income. As a result, for the three months ended March 31, 2013, the pre-tax effects of energy-related derivatives not designated as hedging instruments on Southern Power's statements of income were immaterial.
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, which are all Level 2 of the fair value hierarchy, at March 31, 2013 were as follows:
 
 
 
 
March 31, 2013
Fair Value Measurements
 
 
Total
 
Maturity
 
 
Fair Value
 
Year 1
 
Years 2&3
 
Years 4&5
 
 
(in millions)
Level 1
 
$
—

 
$
—

 
$
—

 
$
—

Level 2
 
3.6

 
2.3

 
0.2

 
1.1

Level 3
 
—

 
—

 
—

 
—

Fair value of contracts outstanding at end of period
 
$
3.6

 
$
2.3

 
$
0.2

 
$
1.1

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"

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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 three months ended March 31, 2013, Southern Power prepaid $0.2 million of long-term debt to TRE.
In March 2013, Southern Power issued an additional $1.7 million under a promissory note, due September 30, 2032, to TRE related to the financing of Spectrum.
Subsequent to March 31, 2013, Southern Power issued a $5.6 million promissory note, due April 30, 2033, to TRE related to the financing of Campo Verde.
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, I, J, K
 
 
Alabama Power
A, B, C, E, F, G, H
 
 
Georgia Power
A, B, C, E, F, G, H
 
 
Gulf Power
A, B, C, E, F, G, H
 
 
Mississippi Power
A, B, C, E, F, G, H
 
 
Southern Power
A, B, C, 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, 2012 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 March 31, 2013 and 2012. 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 (with respect to Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power) and the Form 10-K/A (with respect to Mississippi Power) and details which have not changed significantly in amount or composition since the filings of the Form 10-K or the Form 10-K/A, as applicable, are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K (with respect to Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power) and the Form 10-K/A (with respect to Mississippi Power). 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.
(B)
CONTINGENCIES AND REGULATORY MATTERS
See Note 3 to the financial statements of the registrants (other than Mississippi Power) in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A 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, property damage, and other claims for damages alleged to have been caused by carbon dioxide (CO2) and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, 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 (other than Mississippi Power) in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A, 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.

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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.
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 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 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. In February 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.
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. In September 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. In November 2012, the U.S. Court of Appeals for the Ninth Circuit denied the plaintiffs' request for review of the decision. On February 25, 2013, the plaintiffs filed a petition for writ of certiorari with the U.S. Supreme Court. 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.

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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 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 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. In March 2012, the U.S. District Court for the Southern District of Mississippi dismissed the plaintiffs' amended complaint. In April 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 March 31, 2013 was $18 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.
Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 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 site. In 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. 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 this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. On February 1, 2013, the court granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. The plaintiffs may appeal the court's order to the U.S. Court of Appeals for the Fourth Circuit.
The ultimate outcome of these 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

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result of the regulatory treatment, they are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $57 million as of March 31, 2013. 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 2011 and 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 PRPs. 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
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2. The DOE failed to timely perform and has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel beginning no later than January 31, 1998. Consequently, Alabama Power and Georgia Power have pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered 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, Alabama Power and Georgia Power filed a second lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2. Damages are being sought for the period from January 1, 2005 through December 31, 2010. Damages will continue to accrue until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of March 31, 2013 for any potential recoveries from the second lawsuit. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
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. The facility is expected to begin operation in sufficient time to maintain full-core discharge capability, with additional on-site dry storage to be added as needed. 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.

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FERC Matters
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K/A for additional information regarding Mississippi Power's settlement agreement with its wholesale customers 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 under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A, and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
In 2011, Mississippi Power filed a request with the FERC for an increase in wholesale base revenues under the MRA cost-based electric tariff. In March 2012, Mississippi Power entered into a settlement agreement with its wholesale customers which provided that base revenues would increase by approximately $22.6 million over a 12-month period with revised rates effective for services rendered beginning April 1, 2012. In March 2012, the FERC approved a motion to place interim rates into effect beginning in May 2012. In September 2012, Mississippi Power, with its wholesale customers, filed a final settlement agreement with the FERC. In November 2012, the settlement judge certified the settlement agreement to the FERC with the recommendation that it be approved. The FERC has not yet approved the settlement agreement.
On April 1, 2013, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the MRA cost-based electric tariff. The 2013 settlement agreement provides that base rates under the MRA cost-based electric tariff will increase by approximately $24.2 million over a 12-month period, with revised rates effective for services rendered beginning April 1, 2013. If the 2013 settlement agreement is approved by the FERC, the amount of base rate revenues to be received in 2013 from the agreed upon increase will be approximately $18.0 million.
The ultimate outcome of these matters 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" 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 PPA) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power's under recovered Rate CNP PPA balance at March 31, 2013 was $7 million as compared to $9 million at December 31, 2012. This under recovered balance at March 31, 2013 is included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheet herein. For Rate CNP PPA, this classification is based on an estimate, which includes such factors as purchased power capacity 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. Alabama Power's under recovered Rate CNP Environmental balance at March 31, 2013 was $19 million as compared to $21 million at December 31, 2012. This under recovered balance at March 31, 2013 consists of $11 million in under recovered regulatory clause revenues and $8 million in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. 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.
Retail Energy Cost Recovery
See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Energy Cost Recovery" and "Retail Regulatory Matters – Energy Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's energy cost recovery. Alabama Power's over recovered fuel costs at March 31, 2013 totaled $21 million as compared to an under recovered balance

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of $4 million at December 31, 2012. The over recovered fuel costs at March 31, 2013 are included in other regulatory liabilities, current and the under recovered fuel costs at December 31, 2012 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 March 31, 2013, the NDR had an accumulated balance of $93 million as compared to $103 million at December 31, 2012, which is included on Southern Company's and Alabama Power's Condensed Balance Sheets herein under other regulatory liabilities, deferred. The decrease in the NDR in the first quarter 2013 is a result of storm activity. The related accruals are reflected as operations and maintenance expenses on Southern Company's and Alabama Power's Condensed Statements of Income herein.
Georgia Power
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.
As of March 31, 2013 and December 31, 2012, Georgia Power's fuel cost over recovery balance totaled $182 million and $230 million, respectively, and is included in current liabilities and other deferred credits and liabilities 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.
Integrated Resource Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively, in Item 8 of the Form 10-K for additional information.
On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013. The Georgia PSC is scheduled to vote on all other aspects of the 2013 IRP in July 2013. The ultimate outcome of this matter cannot be determined at this time.
Separately, on April 22, 2013, Georgia Power executed two PPAs to purchase energy from two wind farms with capacity totaling 250 MWs in southwest Oklahoma that will commence in 2016 and end in 2035. In addition, on April 29, 2013, Georgia Power executed a PPA for the purchase of 50 MWs of capacity and energy that will commence in 2015 and end in 2035. These PPAs are subject to Georgia PSC approval and, if approved, will result in contractual obligations of approximately $13 million in 2015, $47 million in 2016, $48 million in 2017, and $1.3 billion thereafter.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the eighth Vogtle Construction Monitoring (VCM) report, and pending litigation.

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In 2008, Georgia Power, acting for itself and as agent for the Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. The Vogtle 3 and 4 Agreement provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.
Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.
In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects through annual adjustments to an NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, and $50 million, effective January 1, 2011, 2012, and 2013, respectively. 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 March 31, 2013, approximately $50 million of these 2009 and 2010 costs remained unamortized in CWIP.
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, effective December 30, 2011, and issued combined construction and operating licenses (COLs) in February 2012. Receipt of the COLs allowed full construction to begin.
In February 2012, separate groups of petitioners filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC's issuance of the COLs and certification of the DCD. These petitions were consolidated in April 2012. Also in April 2012, another group of petitioners filed a motion to stay the effectiveness of the COLs with the U.S. District Court for the District of Columbia. In July 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 is vigorously contesting, these petitions. Additional technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, are expected as construction proceeds.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. On February 19, 2013, the Georgia PSC voted to approve Georgia Power's seventh VCM report, including construction capital costs incurred through June 30, 2012 of approximately $2.0 billion. Georgia Power's eighth VCM report requests approval for an additional $0.2 billion of construction capital costs incurred through December 31, 2012. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, the eighth VCM also requests an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately $2.0 billion. The Georgia PSC is expected to vote on the eighth VCM by October 2013.

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In July 2012, the Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor has claimed that its 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. The Contractor also has asserted it is entitled to further schedule extensions. Georgia Power has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. In November 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 these costs. Also in November 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 these costs. While litigation has commenced and Georgia Power intends to vigorously defend its positions, Georgia Power expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.
In addition, processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including rigorous inspections by Southern Nuclear and the NRC that occur throughout construction. During the fourth quarter 2012, certain details of the rebar design for the Plant Vogtle Unit 3 nuclear island were evaluated for consistency with the DCD and deviations were identified. On February 26, 2013 and March 1, 2013, the NRC approved the two license amendment requests required to conform the rebar design details to NRC requirements and, on March 14, 2013, the placement of basemat structural concrete for the nuclear island of Plant Vogtle Unit 3 was completed. Additional license amendment requests are pending before the NRC. Various design and other issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Owners, the Contractor, or both.
As construction continues, additional delays in the fabrication and assembly of structural modules, the failure of such modules to meet applicable standards, or other issues may further impact project schedule and cost. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.
The ultimate outcome of these matters cannot be determined at this time.
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 May 9, 2013, in accordance with the Florida Administrative Code Rules, Gulf Power notified the Florida PSC of Gulf Power's intent to file for an increase in Gulf Power's base rates, not sooner than July 8, 2013 (60 days after the notification) and not later than July 22, 2013. Gulf Power is proposing the projected 12 months ending December 31, 2014 as the test year for the anticipated rate case filing. The proposed test year is a calendar year that corresponds to Gulf Power's fiscal year and largely corresponds with the first fiscal period that new, permanent rates could be in effect. Gulf Power currently estimates that an increase in annual revenues between $75 million and $80 million will be requested. The ultimate outcome of this matter cannot be determined at this time.
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information.

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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 – Cost Recovery Clauses – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
Over recovered fuel costs at March 31, 2013 totaled $5.1 million compared to $17.1 million at December 31, 2012. 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 – Cost Recovery Clauses – Purchased Power Capacity Recovery," respectively, in Item 8 of the Form 10-K for additional information.
At March 31, 2013 the over recovered purchased power capacity costs totaled $1.8 million, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheets herein. At December 31, 2012, the under recovered purchased power capacity costs totaled $0.8 million, which is included in under recovered regulatory clause revenues 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 – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
Under recovered environmental costs at March 31, 2013 totaled $8.9 million compared to $1.9 million at December 31, 2012. These amounts are included in under recovered regulatory clause revenues 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 – Cost Recovery Clauses – Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.
Under recovered energy conservation costs at March 31, 2013 totaled $3.0 million compared to $0.8 million at December 31, 2012. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.
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/A for additional information regarding Mississippi Power's base rates.
On January 18, 2013, Mississippi Power filed its annual PEP filing for 2013, which indicated a rate increase of 1.990%, or $15.8 million, annually. On March 4, 2013, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) filed a joint stipulation which revised the annual PEP filing for 2013 to reflect the removal of certain costs related to unresolved matters that are currently under review. On March 5, 2013, the revised annual PEP filing for 2013 was approved by the Mississippi PSC, which resulted in a rate increase of 1.925%, or $15.3 million, annually, with the new rates effective March 19, 2013. Mississippi Power may be entitled to $3.3 million in additional revenues in 2013 as a result of the late implementation of the 2013 PEP rate increase.
On March 15, 2013, Mississippi Power submitted its annual PEP lookback filing for 2012, which indicated a refund due to customers of $4.7 million, which was accrued in retail revenues. On May 1, 2013, the MPUS contested the filing.
The ultimate outcome of these matters cannot be determined at this time.

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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/A for information on Mississippi Power's annual environmental filing with the Mississippi PSC.
In April 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. In May 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 March 31, 2013, total project expenditures were $183.2 million, with Mississippi Power's portion being $91.6 million. 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/A for information regarding Mississippi Power's fuel cost recovery.
On January 18, 2013, in compliance with Mississippi Power's filing requirement, Mississippi Power requested an annual adjustment of the retail fuel cost recovery factor in an amount equal to a decrease of 4.7%, or $35.5 million, of total 2012 retail revenue. The Mississippi PSC approved the retail fuel cost recovery factor on March 5, 2013, with the new rates effective March 19, 2013.
At March 31, 2013, the amount of over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $60.9 million compared to $56.6 million at December 31, 2012. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At March 31, 2013, the amount of over recovered wholesale MRA and MB fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $18.1 million and $1.7 million, respectively, compared to $19.0 million and $2.1 million, respectively, at December 31, 2012. In addition, at each of March 31, 2013 and December 31, 2012, the amount of under recovered MRA emissions allowance cost included on Mississippi Power's Condensed Balance Sheets herein was $0.4 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, changes in the billing factor have no significant effect on Mississippi Power's revenues or net income, but will affect 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/A for information regarding Mississippi Power's storm damage cost recovery. 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 March 31, 2013, the balance in the storm reserve was $57.2 million.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Project Approval
In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC (2010 MPSC Order) located in Kemper County, Mississippi. The Sierra Club filed an appeal of the Mississippi PSC's issuance of the CPCN and, in March 2012, the Mississippi Supreme Court reversed the decision of the Chancery Court upholding the 2010 MPSC Order and remanded the matter to the Mississippi PSC. The

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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. In April 2012, the Mississippi PSC issued a detailed order (2012 MPSC Order) confirming the CPCN for the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. In December 2012, the Chancery Court affirmed the 2012 MPSC Order which confirmed the issuance of the CPCN for the Kemper IGCC. On January 8, 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.
The Kemper IGCC is currently under construction and will utilize an integrated coal gasification combined cycle technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC that is scheduled to begin operations in June 2013. In connection with the Kemper IGCC, Mississippi Power also is constructing and plans to operate approximately 61 miles of carbon dioxide (CO2) pipeline infrastructure. The Kemper IGCC and the CO2 pipeline are scheduled to be placed in service in May 2014. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO2 Pipeline Facilities" in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO2 Pipeline Facilities" in Item 8 of the Form 10-K/A for additional information regarding the lignite mine and the CO2 pipeline.
The ultimate outcome of the CPCN challenge cannot be determined at this time.
Kemper IGCC Cost Estimate
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC Order was $2.4 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants), the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions as contemplated in the Settlement Agreement (described below) and the 2012 MPSC Order, which includes change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers, relative to the original proposal for the CPCN) (Cost Cap Exceptions). Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.
On April 23, 2013, Mississippi Power revised its cost estimate for the Kemper IGCC to approximately $3.42 billion, net of the DOE Grants and the Cost Cap Exceptions. Estimated amounts of the Cost Cap Exceptions include $245 million for the lignite mine and equipment, $132 million for the CO2 pipeline facilities, $324 million of AFUDC, and $102 million of other general exceptions. The revised cost estimate reflects additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, and productivity decreases. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for amounts subject to the Cost Cap Exceptions.
As a result of an evaluation of the revised cost estimate, Mississippi Power determined that a portion of this $540 million estimated probable loss related to the period ended December 31, 2012. Accordingly, Mississippi Power restated its 2012 financial statements to reflect a pre-tax charge to income for this estimated probable loss of $78.0 million ($48.2 million after tax) in 2012, with the additional $462.0 million ($285.3 million after tax) reflected in the first quarter 2013. Southern Company evaluated the portion of the estimated probable loss related to 2012 and concluded it was not material to Southern Company. Therefore, Southern Company reflected the total pre-tax charge to income for this estimated probable loss of $540.0 million ($333.5 million after tax) in the first quarter 2013.
Southern Company's and Mississippi Power's analysis of the estimated cost to complete the Kemper IGCC will be ongoing throughout the construction period. It is possible that Mississippi Power could experience further cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors 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, delays

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associated with start-up activities, and/or unforeseen engineering problems. In subsequent periods, any changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.
As of March 31, 2013, Mississippi Power had spent a total of $2.88 billion on the Kemper IGCC, excluding the estimated probable loss. These costs include $2.41 billion for the portion of the Kemper IGCC subject to the construction cost cap, $188.9 million for the lignite mine and equipment, $84.4 million for the CO2 pipeline facilities, $156.4 million of AFUDC, and $43.1 million of other costs, including certain general exceptions and certain regulatory assets. Of this total, $2.29 billion was included in CWIP (which is net of the DOE Grants and an estimated probable loss of $540 million), $43.4 million in other regulatory assets, $3.8 million in other deferred charges and assets on Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.0 million was previously expensed. Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings.
The ultimate outcome of these matters cannot be determined at this time.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" for additional information regarding Mississippi Power's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Baseload Act" herein for additional information.
On January 24, 2013, Mississippi Power entered into a settlement agreement (Settlement Agreement) with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC. Under the Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions as well as any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. Mississippi Power intends to finance (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and the Cost Cap Exceptions, (2) the accrued AFUDC, and (3) exceptions not provided for in the Seven-Year Rate Plan (discussed below) through securitization as provided in State of Mississippi legislation. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective after the Kemper IGCC is placed in service and following completion of the Mississippi PSC's final prudence review of costs for the Kemper IGCC.
Under the terms of the Settlement Agreement, Mississippi Power and the Mississippi PSC agreed to follow certain regulatory procedures and schedules for resolving the cost recovery matters related to the Kemper IGCC. These procedures and schedules include the following: (1) Mississippi Power's filing on January 25, 2013 of a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service; (2) the Mississippi PSC's decision on that matter on March 5, 2013 as described below; (3) Mississippi Power's collaboration with the MPUS to file with the Mississippi PSC within three months of the Settlement Agreement a rate recovery plan for the Kemper IGCC for the first seven years of its operation, along with a proposed revenue requirement under such plan for 2014 through 2020 (Seven-Year Rate Plan) (which was made on February 26, 2013 and updated on March 22, 2013 as described below); (4) the Mississippi PSC's decision on the Seven-Year Rate Plan within four months of that filing (which is now expected to occur in the fall of 2013); (5) Mississippi Power's agreement to limit the portion of prudently-incurred Kemper IGCC costs to be included in rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, excluding AFUDC, provided that this limitation will not prevent Mississippi Power from securing alternate financing to recover any prudently-incurred Kemper IGCC costs, including plant costs above the $2.4 billion certificated cost estimate and AFUDC, not otherwise recovered in

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any Mississippi PSC rate proceeding contemplated by the Settlement Agreement; and (6) the Mississippi PSC's completion of its prudence review of the Kemper IGCC costs incurred through 2012 within six months of the Settlement Agreement, an additional prudence review upon considering the Seven-Year Rate Plan for costs incurred through the most recent reporting period, and a final prudence review of the remaining project costs within six months of the Kemper IGCC's in-service date. The Settlement Agreement provides that Mississippi Power may terminate the agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization was enacted into law on February 26, 2013. Mississippi Power is currently working with the Mississippi PSC and the MPUS to implement the procedural schedules set forth in the Settlement Agreement and variations to the schedule are likely.
On March 5, 2013, the Mississippi PSC issued an order (2013 Kemper IGCC Order) approving a 15% increase in retail rates effective on March 19, 2013, and an additional 3% increase in retail rates effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. All amounts collected through April 2014, which are expected to total $126 million, will be recorded as a regulatory liability to be used to mitigate rate impacts beginning in May 2014 when the Kemper IGCC is expected to be placed in service. On March 21, 2013, a legal challenge to the 2013 Kemper IGCC Order was filed with the Mississippi Supreme Court.
Because the 2013 Kemper IGCC Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act described below, Mississippi Power continues to record AFUDC on the Kemper IGCC during the construction period. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power's rate plans filed pursuant to the Settlement Agreement contemplate the continued accrual of AFUDC through the May 2014 expected in-service date.
On March 22, 2013, Mississippi Power, in compliance with the 2013 Kemper IGCC Order, filed a revision to the Seven-Year Rate Plan with the Mississippi PSC for the Kemper IGCC for 2014 through 2020, the first seven years of operation of the Kemper IGCC. The Seven-Year Rate Plan, which contemplates Mississippi Power's sale of a 15% undivided ownership interest in the Kemper IGCC, proposes recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 Kemper IGCC Order, which increased rates beginning on March 19, 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the April 2014 regulatory liability balance to be used to mitigate rate impacts from the expected in-service date of May 2014 through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan filing, Mississippi Power proposes annual rate recovery to remain the same from 2014 through 2020. While it is the intent of Mississippi Power for the actual revenue requirement to equal the proposed revenue requirement, Mississippi Power proposes that the annual differences through 2020 for certain items contemplated in the Seven-Year Rate Plan will be deferred, subject to accrual of carrying costs, and the cumulative balance will be reviewed at the end of the term of the Settlement Agreement by the Mississippi PSC to determine the disposition of any potential remaining deferred balance.
The revenue requirements set forth in Mississippi Power's Seven-Year Rate Plan described above assume, among other things, the Kemper IGCC will be placed in service in May 2014, the sale of a 15% undivided interest in the Kemper IGCC to SMEPA will be completed as described herein, Mississippi Power's receipt of the benefits relating to tax credits described herein, and recovery of the Cost Cap Exceptions described herein.
The ultimate outcome of these matters, including the determinations of prudency and the specific manner of recovery of costs relating to the Kemper IGCC, is subject to further regulatory actions and cannot be determined at this time.

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Proposed Sale of Undivided Interest to SMEPA
In 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 February 2012, the Mississippi PSC approved the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. In June 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. On December 31, 2012, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2013.
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. In September 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.
In March 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 Southern Company's and Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Southern Company's and Mississippi Power's Condensed Statements of Cash Flows herein.
The ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi and is designed to enhance the Mississippi PSC's authority to facilitate development and construction of base load generation in the State of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of the legal challenges to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.
Tax Incentives
The IRS has allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Mississippi Power's 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 March 31, 2013, Mississippi Power had received or accrued tax benefits totaling $412 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. As a result of bonus tax depreciation on certain assets placed, or to be placed, in service in 2012 and 2013, and the subsequent reduction in federal taxable income, Mississippi Power estimates that it will not be able to

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utilize $178.8 million of these tax credits until after March 31, 2014. IRS guidelines allow these unused tax credits to be carried forward for 20 years from the date received, if not utilized before then. In October 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 as described above. In addition, all or a portion of the tax credits will be subject to recapture if Mississippi Power fails to satisfy the in-service date requirements and CO2 capture requirements described above.
On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and 50% bonus depreciation for property to be placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is expected to apply to the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
On April 4, 2013, an explosion occurred at Plant Bowen Unit 2 that resulted in substantial damage to the Plant Bowen Unit 2 generator, Plant Bowen's Units 1 and 2 control room and surrounding areas, as well as Plant Bowen's switchyard. The extent of the damage sustained by Plant Bowen Unit 1 is unknown. Plant Bowen Units 1 and 2 (approximately 1,400 MWs) remain offline, pending assessment of the damage and completion of repairs. Georgia Power expects that any material repair costs related to the damage will be covered by property insurance. The ultimate outcome of this matter cannot be determined at this time.


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(C)
FAIR VALUE MEASUREMENTS
As of March 31, 2013, 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 March 31, 2013:
 
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
 
$
—

 
$
50

 
$
—

 
$
50

Interest rate derivatives
 
—

 
10

 
—

 
10

Nuclear decommissioning trusts(a)
 
526

 
838

 
—

 
1,364

Cash equivalents
 
223

 
—

 
—

 
223

Other investments
 
9

 
—

 
15

 
24

Total
 
$
758

 
$
898

 
$
15

 
$
1,671

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
63

 
$
—

 
$
63

 
 
 
 
 
 
 
 
 
Alabama Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
12

 
$
—

 
$
12

Nuclear decommissioning trusts:(b)
 
 
 
 
 
 
 
 
Domestic equity
 
320

 
69

 
—

 
389

Foreign equity
 
30

 
56

 
—

 
86

U.S. Treasury and government agency securities
 
—

 
29

 
—

 
29

Corporate bonds
 
—

 
101

 
—

 
101

Mortgage and asset backed securities
 
—

 
25

 
—

 
25

Other
 
—

 
10

 
—

 
10

Total
 
$
350

 
$
302

 
$
—

 
$
652

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
7

 
$
—

 
$
7


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Fair Value Measurements Using
 
 
As of March 31, 2013:
 
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
 
$
—

 
$
13

 
$
—

 
$
13

Nuclear decommissioning trusts:(b) (c)
 
 
 
 
 
 
 
 
Domestic equity
 
176

 
1

 
—

 
177

Foreign equity
 
—

 
120

 
—

 
120

U.S. Treasury and government agency securities
 
—

 
130

 
—

 
130

Municipal bonds
 
—

 
28

 
—

 
28

Corporate bonds
 
—

 
130

 
—

 
130

Mortgage and asset backed securities
 
—

 
121

 
—

 
121

Other
 
—

 
18

 
—

 
18

Cash equivalents
 
27

 
—

 
—

 
27

Total
 
$
203

 
$
561

 
$
—

 
$
764

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
28

 
$
—

 
$
28

 
 
 
 
 
 
 
 
 
Gulf Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
14

 
$
—

 
$
14

Cash equivalents
 
16

 
—

 
—

 
16

Total
 
$
16

 
$
14

 
$
—

 
$
30

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
16

 
$
—

 
$
16

 
 
 
 
 
 
 
 
 
Mississippi Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
6

 
$
—

 
$
6

Cash equivalents
 
122

 
—

 
—

 
122

Total
 
$
122

 
$
6

 
$
—

 
$
128

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
11

 
$
—

 
$
11

 
 
 
 
 
 
 
 
 
Southern Power
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
5

 
$
—

 
$
5

Cash equivalents
 
27

 
—

 
—

 
27

Total
 
$
27

 
$
5

 
$
—

 
$
32

Liabilities:
 
 
 
 
 
 
 
 
Energy-related derivatives
 
$
—

 
$
1

 
$
—

 
$
1

 
(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.

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(c)
Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of March 31, 2013, approximately $68 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.
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 March 31, 2013, 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 March 31, 2013:
 
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
 
 
     (in millions)
 
 
 
 
Southern Company
 
 
 
 
 
 
Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
Foreign equity funds
 
$
120

 
None
 
Monthly
 
5 days
Corporate bonds - commingled funds
 
7

 
None
 
Daily
 
1 to 3 days
Other - commingled funds
 
74

 
None
 
Daily/Monthly
 
Daily/7 days
Trust-owned life insurance
 
100

 
None
 
Daily
 
15 days
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
223

 
None
 
Daily
 
Not applicable
Alabama Power
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
Other - commingled funds
 
56

 
None
 
Daily/Monthly
 
Daily/7 days
Trust-owned life insurance
 
100

 
None
 
Daily
 
15 days
Georgia Power
 
 
 
 
 
 
 
 
Nuclear decommissioning trusts:
 
 
 
 
 
 
 
 
Foreign equity funds
 
120

 
None
 
Monthly
 
5 days
Corporate bonds - commingled funds
 
7

 
None
 
Daily
 
Not applicable
Other - commingled funds
 
18

 
None
 
Daily
 
Not applicable
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
27

 
None
 
Daily
 
Not applicable
Gulf Power
 
 
 
 
 
 
 
 
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
16

 
None
 
Daily
 
Not applicable
Mississippi Power
 
 
 
 
 
 
 
 
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
122

 
None
 
Daily
 
Not applicable
Southern Power
 
 
 
 
 
 
 
 
Cash equivalents:
 
 
 
 
 
 
 
 
Money market funds
 
27

 
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 foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities and depository receipts, including American depositary receipts, European depositary receipts and global depository receipts, and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.
The commingled funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of

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indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations with maturity shortening provisions. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The commingled funds included with corporate bonds 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.
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 months ended March 31, 2013, the fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $59 million at Southern Company. Alabama Power recorded an increase in fair value of $38 million as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $21 million as a reduction of its regulatory asset related to its asset retirement obligations.
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.
As of March 31, 2013, 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
 
$
21,915

 
$
23,644

Alabama Power
 
$
6,179

 
$
6,853

Georgia Power
 
$
9,639

 
$
10,316

Gulf Power
 
$
1,246

 
$
1,353

Mississippi Power
 
$
2,211

 
$
2,294

Southern Power
 
$
1,308

 
$
1,448

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates 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
March 31, 2013
 
Three Months
Ended
March 31, 2012
 
 
(in millions)
As reported shares
 
870

 
868

Effect of options and performance share award units
 
5

 
9

Diluted shares
 
875

 
877

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three months ended March 31, 2013 and 2012.
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, 2012
 
877,803

 
(10,035
)
 
$
18,297

 
$
707

 
$
19,004

Net income after dividends on preferred and preference stock
 
—

 
—

 
81

 
—

 
81

Other comprehensive income (loss)
 
—

 
—

 
4

 
—

 
4

Stock issued
 
2,638

 
—

 
99

 
—

 
99

Stock repurchased, at cost
 
—

 
—

 
(18
)
 
—

 
(18
)
Cash dividends on common stock
 
—

 
—

 
(426
)
 
—

 
(426
)
Other
 
—

 
(15
)
 
—

 
—

 
—

Balance at March 31, 2013
 
880,441

 
(10,050
)
 
$
18,037

 
$
707

 
$
18,744

 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2011
 
865,664

 
(539
)
 
$
17,578

 
$
707

 
$
18,285

Net income after dividends on preferred and preference stock
 
—

 
—

 
368

 
—

 
368

Other comprehensive income (loss)
 
—

 
—

 
6

 
—

 
6

Stock issued
 
3,571

 
—

 
157

 
—

 
157

Cash dividends on common stock
 
—

 
—

 
(410
)
 
—

 
(410
)
Other
 
—

 
(6
)
 
—

 
—

 
—

Balance at March 31, 2012
 
869,235

 
(545
)
 
$
17,699

 
$
707

 
$
18,406

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. As of December 31, 2012, Southern Company had repurchased a total of approximately 9 million shares at a total cost of $430 million. There were no repurchases

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under this program in the first quarter 2013. Pursuant to approval by the Southern Company Board of Directors, 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 (other than Mississippi Power) under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K/A for additional information.

The following table outlines the committed credit arrangements by company as of March 31, 2013: 

 
 
Expires(a)
 
 
 
Executable Term
Loans
 
Due Within  One
Year
Company
 
2013
 
2014
 
2016
 
2018
 
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
 
156

 
151

 
—

 
1,000

 
1,307

 
1,307

 
56

 
—

 
56

 
102

Georgia Power
 
—

 
—

 
150

 
1,600

 
1,750

 
1,740

 
—

 
—

 
—

 
—

Gulf Power
 
45

 
60

 
165

 
—

 
270

 
270

 
45

 
—

 
45

 
30

Mississippi Power
 
110

 
25

 
165

 
—

 
300

 
300

 
25

 
40

 
65

 
70

Southern Power
 
—

 
—

 
—

 
500

 
500

 
500

 
—

 
—

 
—

 
—

Other
 
50

 
—

 
—

 
—

 
50

 
50

 
25

 
—

 
25

 
25

Total
 
$
361

 
$
236

 
$
480

 
$
4,100

 
$
5,177

 
$
5,167

 
$
151

 
$
40

 
$
191

 
$
227

 
(a)
No credit arrangements expire in 2015 or 2017.
In February 2013, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended their multi-year credit arrangements, which extended the maturity dates from 2016 to 2018.
In March 2013, Alabama Power amended a $200 million credit arrangement, which extended the maturity date from 2014 to 2018. In March 2013, Gulf Power also amended a $35 million credit arrangement, which reduced the amount to $30 million and extended the maturity date from 2013 to 2014. In addition, in March 2013, Georgia Power, Gulf Power, and Mississippi Power each amended certain of their credit arrangements, which extended the maturity dates from 2014 to 2016 and, in the case of Mississippi Power, also revised the definition of debt to exclude securitized debt relating to the Kemper IGCC for purposes of calculating the debt covenant under these credit arrangements. See Note (B) under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
Subsequent to March 31, 2013, Gulf Power entered into a new credit arrangement for $5 million with a maturity date of 2014.
Also subsequent to March 31, 2013, SEGCO entered into two new $25 million credit arrangements with maturity dates of 2014.
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.

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(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, 2013. 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, and Gulf Power in Item 8 of the Form 10-K and Note 2 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A for additional information.

Components of the net periodic benefit costs for the three months ended March 31, 2013 and 2012 were as follows:
 
Pension Plans
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
  Mississippi  
Power
 
 
(in millions)
Three Months Ended March 31, 2013
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
58

 
$
13

 
$
17

 
$
3

 
$
3

Interest cost
 
97

 
23

 
34

 
4

 
5

Expected return on plan assets
 
(151
)
 
(39
)
 
(53
)
 
(6
)
 
(7
)
Amortization:
 
 
 
 
 
 
 
 
 
 
Prior service costs
 
7

 
2

 
3

 
—

 
—

Net (gain)/loss
 
50

 
13

 
19

 
2

 
2

Net cost
 
$
61

 
$
12

 
$
20

 
$
3

 
$
3

Three Months Ended March 31, 2012
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
50

 
$
11

 
$
15

 
$
2

 
$
2

Interest cost
 
98

 
23

 
35

 
4

 
5

Expected return on plan assets
 
(145
)
 
(40
)
 
(55
)
 
(6
)
 
(6
)
Amortization:
 
 
 
 
 
 
 
 
 
 
Prior service costs
 
7

 
2

 
3

 
—

 
—

Net (gain)/loss
 
24

 
6

 
8

 
1

 
1

Net cost
 
$
34

 
$
2

 
$
6

 
$
1

 
$
2



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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 March 31, 2013
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
6

 
$
2

 
$
2

 
$
—

 
$
—

Interest cost
 
19

 
5

 
8

 
1

 
1

Expected return on plan assets
 
(14
)
 
(6
)
 
(6
)
 
—

 
—

Amortization:
 
 
 
 
 
 
 
 
 
 
Transition obligation
 
1

 
—

 
1

 
—

 
—

Prior service costs
 
1

 
1

 
—

 
—

 
—

Net (gain)/loss
 
3

 
—

 
2

 
—

 
—

Net cost
 
$
16

 
$
2

 
$
7

 
$
1

 
$
1

Three Months Ended March 31, 2012
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
5

 
$
1

 
$
1

 
$
—

 
$
—

Interest cost
 
21

 
5

 
9

 
1

 
1

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

 
—

Amortization:
 
 
 
 
 
 
 
 
 
 
Transition obligation
 
2

 
1

 
2

 
—

 
—

Prior service costs
 
1

 
1

 
—

 
—

 
—

Net (gain)/loss
 
2

 
—

 
1

 
—

 
—

Net cost
 
$
16

 
$
2

 
$
6

 
$
1

 
$
1




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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(G)
EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
Effective Tax Rate
See Note 5 to the financial statements of each registrant (other than Mississippi Power) in Item 8 of the Form 10-K and Note 5 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A 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 24.5% for the three months ended March 31, 2013 compared to 34.2% for the corresponding period in 2012. The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code (production activities deduction). The decrease was primarily due to an increase in non-taxable AFUDC equity primarily related to Mississippi Power's construction of the Kemper IGCC combined with lower net income. The decrease was partially offset by the recognition in 2012 of previously unrecognized tax benefits as a result of a settlement with the IRS related to the methodology used to calculate the production activities deduction.
Alabama Power
Alabama Power's effective tax rate was 39.2% for the three months ended March 31, 2013 compared to 38.3% for the corresponding period in 2012. The increase was primarily due to the recognition in 2012 of previously unrecognized tax benefits as a result of a settlement with the IRS related to the production activities deduction.
Georgia Power
Georgia Power's effective tax rate was 38.1% for the three months ended March 31, 2013 compared to 34.9% for the corresponding period in 2012. The increase was primarily due to an increase in non-deductible book depreciation, the recognition in 2012 of previously unrecognized tax benefits as a result of a settlement with the IRS related to the production activities deduction, and a decrease in non-taxable AFUDC equity.
Gulf Power
Gulf Power's effective tax rate was 37.6% for the three months ended March 31, 2013 compared to 34.6% for the corresponding period in 2012. The increase was primarily due to the recognition in 2012 of previously unrecognized tax benefits as a result of a settlement with the IRS related to the production activities deduction.
Mississippi Power
Mississippi Power's effective tax rate was (40.8)% for the three months ended March 31, 2013 compared to 24.7% for the corresponding period in 2012. The decrease was primarily due to a net loss for the current period and an increase in non-taxable AFUDC equity related to construction of the Kemper IGCC.
Southern Power
Southern Power's effective tax rate was 33.5% for the three months ended March 31, 2013 compared to 31.3% for the corresponding period in 2012. The increase was primarily due to the recognition in 2012 of previously unrecognized tax benefits as a result of a settlement with the IRS related to the production activities deduction.

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Unrecognized Tax Benefits
Changes during 2013 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, 2012
 
$
70

 
$
31

 
$
23

 
$
5

 
$
6

 
$
3

Tax positions from current periods
 
3

 
1

 
1

 
—

 
—

 
—

Balance as of March 31, 2013
 
$
73

 
$
32

 
$
24

 
$
5

 
$
6

 
$
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 Property Related Expenditures" herein for additional information.
The impact on the effective tax rate, if recognized, was as follows:
 
 
 
As of March 31, 2013
 
As of
December 31, 2012
 
 
 
 
Southern Company
 
 
(in millions)
Tax positions impacting the effective tax rate
 
 
 
$
5

 
$
5

Tax positions not impacting the effective tax rate
 
 
 
68

 
65

Balance of unrecognized tax benefits
 
 
 
$
73

 
$
70

The tax positions impacting the effective tax rate primarily relate to state income tax credits. 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 Property Related Expenditures" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
All of the registrants classify interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits at March 31, 2013 and December 31, 2012 was not material.
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 12 months. The resolution of the tax accounting method change for repairs-generation assets, as well as the conclusion or settlement of state audits, could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
Tax Method of Accounting for Property Related Expenditures
Southern Company submitted a tax accounting method change related to the deductibility of repair costs associated with its subsidiaries' generation, transmission, and distribution systems effective for the 2009 consolidated federal income tax return in 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. Consequently, Southern Company incorporated into its federal income tax returns changes that conform to the new regulations and reversed all unrecognized tax positions related to transmission and distribution property.
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, 2014. The utility industry anticipates more detailed guidance concerning these regulations. Additionally, on April 30, 2013, the IRS issued

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Southern Company is currently reviewing this new guidance. Due to uncertainty regarding the ultimate resolution of the repair costs for generation assets, an unrecognized tax position was recorded for the tax accounting method change for repairs-generation assets. The ultimate outcome of these matters cannot be determined at this time; however, implementing these regulations is not expected to have a material impact on net income.
(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. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.
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 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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At March 31, 2013, 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
 
259

 
2017

 
2017

Alabama Power
 
58

 
2017

 
—

Georgia Power
 
90

 
2017

 
—

Gulf Power
 
70

 
2017

 
—

Mississippi Power
 
36

 
2017

 
—

Southern Power
 
5

 
—

 
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 11 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 1 million mmBtu for Mississippi Power, and 3 million mmBtu for Southern Power.
For cash flow hedges, the amounts expected to be reclassified from AOCI to revenue and fuel expense for the next 12-month period ending March 31, 2014 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow 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 March 31, 2013, the following interest rate derivatives were outstanding:
 
 
 
Notional
Amount
 
Interest Rate
Received
 
Interest Rate
Paid
 
Hedge
Maturity Date
 
Fair Value
Gain (Loss)
March 31, 2013
 
 
(in millions)
 
 
 
 
 
 
 
(in millions)
Fair value hedges of existing debt
 
 
 
 
 
 
 
 
 
 
Southern Company
 
$
350

 
4.15
%
 
3-month
LIBOR  +
1.96%
(a) 
May 2014
 
$
10

(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 AOCI to interest expense for the next 12-month period ending March 31, 2014, 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
March 31, 2014
 
Total Deferred
Gains (Losses)
Amortized
 Through
 
 
(in millions)
 
 
Southern Company
 
$
(12
)
 
2037
Alabama Power
 
(3
)
 
2035
Georgia Power
 
(3
)
 
2037
Gulf Power
 
(1
)
 
2020
Mississippi Power
 
(1
)
 
2022
Southern Power
 
(4
)
 
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 March 31, 2013, the fair value of the foreign currency derivatives outstanding was immaterial.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

 Derivative Financial Statement Presentation and Amounts
At March 31, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
Asset Derivatives at March 31, 2013
 
 
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
 
$
25

 
$
7

 
$
6

 
$
9

 
$
3

 
 
Other deferred charges and assets
 
20

 
5

 
7

 
5

 
3

 
 
Total derivatives designated as hedging instruments for regulatory purposes
 
$
45

 
$
12

 
$
13

 
$
14

 
$
6

 
N/A

Derivatives designated as hedging instruments in cash flow and fair value hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Other current assets
 
$
7

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Other deferred charges and assets
 
3

 
—

 
—

 
—

 
—

 
—

Total derivatives designated as hedging instruments in cash flow and fair value hedges
 
$
10

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Assets from risk management activities
 
$
3

 
$
—

 
$
—

 
$
—

 
$
—

 
$
3

Other deferred charges and assets
 
2

 
—

 
—

 
—

 
—

 
2

Total derivatives not designated as hedging instruments
 
$
5

 
$
—

 
$
—

 
$
—

 
$
—

 
$
5

Total asset derivatives
 
$
60

 
$
12

 
$
13

 
$
14

 
$
6

 
$
5


Liability Derivatives at March 31, 2013
 
 
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
 
$
36

 
$
5

 
$
17

 
$
8

 
$
6

 
 
Other deferred credits and liabilities
 
26

 
2

 
11

 
8

 
5

 
 
Total derivatives designated as hedging instruments for regulatory purposes
 
$
62

 
$
7

 
$
28

 
$
16

 
$
11

 
N/A

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

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1

Total liability derivatives
 
$
63

 
$
7

 
$
28

 
$
16

 
$
11

 
$
1


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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At December 31, 2012, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 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
 
$
10

 
$
2

 
$
6

 
$
1

 
$
1

 
 
Other deferred charges and assets
 
13

 
3

 
5

 
3

 
2

 
 
Total derivatives designated as hedging instruments for regulatory purposes
 
$
23

 
$
5

 
$
11

 
$
4

 
$
3

 
N/A

Derivatives designated as hedging instruments in cash flow and fair value hedges
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Other current assets
 
$
7

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Other deferred charges and assets
 
3

 
—

 
—

 
—

 
—

 
—

Total derivatives designated as hedging instruments in cash flow and fair value hedges
 
$
10

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

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

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1

Other deferred charges and assets
 
2

 
—

 
—

 
—

 
—

 
2

Total derivatives not designated as hedging instruments
 
$
3

 
$
—

 
$
—

 
$
—

 
$
—

 
$
3

Total asset derivatives
 
$
36

 
$
5

 
$
11

 
$
4

 
$
3

 
$
3


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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Liability Derivatives at December 31, 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
 
$
74

 
$
14

 
$
30

 
$
17

 
$
13

 


Other deferred credits and liabilities
 
35

 
4

 
15

 
10

 
6

 


Total derivatives designated as hedging instruments for regulatory purposes
 
$
109

 
$
18

 
$
45

 
$
27

 
$
19

 
N/A

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

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1

Other deferred credits and liabilities
 
1

 
—

 
—

 
—

 
—

 
1

Total derivatives not designated as hedging instruments
 
$
2

 
$
—

 
$
—

 
$
—

 
$
—

 
$
2

Total liability derivatives
 
$
111

 
$
18

 
$
45

 
$
27

 
$
19

 
$
2

All derivative instruments are measured at fair value. See Note (C) herein for additional information.
Balance Sheet Offsetting
The derivative contracts of Southern Company, the traditional operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Derivative Contracts at March 31, 2013
 
 
Fair Value
 
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern  
Power

 
(in millions)
Assets
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives presented in the Balance Sheet (a)
 
$
50

 
$
12

 
$
13

 
$
14

 
$
6

 
$
5

Gross amounts not offset in the Balance Sheet (b)
 
(39
)
 
(5
)
 
(13
)
 
(10
)
 
(5
)
 
(1
)
Net energy-related derivative assets
 
$
11

 
$
7

 
$
—

 
$
4

 
$
1

 
$
4

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives presented in the Balance Sheet (a)
 
$
63

 
$
7

 
$
28

 
$
16

 
$
11

 
$
1

Gross amounts not offset in the Balance Sheet (b)
 
(39
)
 
(5
)
 
(13
)
 
(10
)
 
(5
)
 
(1
)
Net energy-related derivative liabilities
 
$
24

 
$
2

 
$
15

 
$
6

 
$
6

 
$
—

(a) None of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
Derivative Contracts at December 31, 2012
 
 
Fair Value
 
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern  
Power
 
 
(in millions)
Assets
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives presented in the Balance Sheet (a)
 
$
26

 
$
5

 
$
11

 
$
4

 
$
3

 
$
3

Gross amounts not offset in the Balance Sheet (b)
 
(23
)
 
(4
)
 
(11
)
 
(4
)
 
(2
)
 
(1
)
Net energy-related derivative assets
 
$
3

 
$
1

 
$
—

 
$
—

 
$
1

 
$
2

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Energy-related derivatives presented in the Balance Sheet (a)
 
$
111

 
$
18

 
$
45

 
$
27

 
$
19

 
$
2

Gross amounts not offset in the Balance Sheet (b)
 
(23
)
 
(4
)
 
(11
)
 
(4
)
 
(2
)
 
(1
)
Net energy-related derivative liabilities
 
$
88

 
$
14

 
$
34

 
$
23

 
$
17

 
$
1

(a) None of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At March 31, 2013 and December 31, 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 at March 31, 2013
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
 
$
(36
)
 
$
(5
)
 
$
(17
)
 
$
(8
)
 
$
(6
)
Other regulatory assets, deferred
 
(26
)
 
(2
)
 
(11
)
 
(8
)
 
(5
)
Other regulatory liabilities, current
 
25

 
7

 
6

 
9

 
3

Other regulatory liabilities, deferred
 
20

 
5

 
—

 
5

 
3

Other deferred credits and liabilities(a)
 
—

 
—

 
7

 
—

 
—

Total energy-related derivative gains (losses)
 
$
(17
)
 
$
5

 
$
(15
)
 
$
(2
)
 
$
(5
)
(a)
Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2012
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
 
$
(74
)
 
$
(14
)
 
$
(30
)
 
$
(17
)
 
$
(13
)
Other regulatory assets, deferred
 
(35
)
 
(4
)
 
(15
)
 
(10
)
 
(6
)
Other regulatory liabilities, current
 
10

 
2

 
6

 
1

 
1

Other regulatory liabilities, deferred
 
13

 
3

 
—

 
3

 
2

Other deferred credits and liabilities(a)
 
—

 
—

 
5

 
—

 
—

Total energy-related derivative gains (losses)
 
$
(86
)
 
$
(13
)
 
$
(34
)
 
$
(23
)
 
$
(16
)
(a)
Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.
For the three months ended March 31, 2013 and March 31, 2012, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company's statements of income were immaterial.
For the three months ended March 31, 2013 and March 31, 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 and 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended March 31, 2013 and 2012, 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 AOCI into
Income (Effective Portion)
 
 
Statements of Income Location
 
Amount
 
 
2013
 
2012
 
 
 
2013
 
2012
 
 
(in millions)
 
 
 
(in millions)
Southern Company
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
—

 
$
6

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

 
$
7

 
Interest expense, net of amounts capitalized
 
$
(1
)
 
$
—

Georgia Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
—

 
$
—

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

 
$
(1
)
 
Interest expense, net of amounts capitalized
 
$
—

 
$
—

Southern Power
 
 
 
 
 
 
 
 
 
 
Interest rate derivatives
 
$
—

 
$
—

 
Interest expense, net of amounts capitalized
 
$
(3
)
 
$
(2
)

For the three months ended March 31, 2013 and 2012, 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 months ended March 31, 2013 and 2012, 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 months ended March 31, 2013 and March 31, 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 March 31, 2013, 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
 
$
1

 
$
—

 
$
2

 
$
—

 
$
—

 
$
—

At March 31, 2013, 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. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $1 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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants have 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.
(I)
ACQUISITIONS
Campo Verde Solar, LLC Acquisition
On April 23, 2013, Southern Power and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power , acquired all of the outstanding membership interests of Campo Verde Solar, LLC (Campo Verde) from First Solar, Inc., the developer of the project. Campo Verde is constructing a 139-MW solar photovoltaic facility in Southern California. The solar facility is expected to begin commercial operation in the fourth quarter 2013. The output of the plant is contracted under a 20-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy, that is expected to begin in the fourth quarter 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 Campo Verde included cash consideration of $136.6 million. The allocation of the purchase price to individual assets has not been finalized. Under an engineering, procurement, and construction agreement (Construction Agreement), an additional $357.3 million will be paid to a subsidiary of First Solar, Inc. (Construction Contractor) to complete construction of the solar facility.
In the event certain unforeseeable conditions occur at the project site, the Construction Contractor may terminate the Construction Agreement, and in the event the Construction Contractor does not achieve certain construction or project development milestones by certain dates, STR may terminate the Construction Agreement. In each case, a subsidiary of First Solar will be required to make a termination payment to STR equal to STR's investment in Campo Verde (net of any tax or other benefits received by STR) and STR will be required to transfer its ownership in Campo Verde to the subsidiary of First Solar (the Termination Payment and Transfer). In addition, under the acquisition agreement, a subsidiary of First Solar may require the Termination Payment and Transfer to occur in the event costs relating to certain contingencies exceed a certain threshold until such time that the contingencies are satisfactorily resolved under the terms of the acquisition agreement, and STR may require the Termination Payment and Transfer to occur in the event certain contingencies are not satisfactorily resolved. The ultimate outcome of this matter cannot be determined at this time; however, STR believes the likelihood of a Termination Payment and Transfer to be remote at the acquisition date.


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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(J) 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.
On March 1, 2013, Southern Company completed the restructuring of the nonrecourse debt and the related rental payments associated with its leveraged lease investment in a 440-MW generation facility located in Choctaw County, Mississippi. In connection with the restructuring, Southern Company has committed, as owner/lessor, to invest approximately $60 million in capital over the next three years to improve the operational performance of the facility and upgrade environmental controls. As part of the restructuring, the interest rate on the nonrecourse debt was significantly reduced, resulting in lower debt payments for Southern Company and lower rental payments for the lessee over the remaining 19-year term of the nonrecourse debt and the lease. As a consequence of the restructuring, Southern Company recalculated its net investment in the lease to reflect changes in the future cash flows to Southern Company as owner/lessor. As a result of the recalculation, Southern Company recorded an after-tax charge to income during the first quarter 2013 of approximately $16 million. This noncash charge reflects a reallocation of previously recognized lease income that will be reflected in income over the remaining term of the lease.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(K) 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 $78 million and $112 million for the three months ended March 31, 2013 and March 31, 2012, 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 March 31, 2013:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
3,668

 
$
303

 
$
(86
)
 
$
3,885

 
$
35

 
$
(23
)
 
$
3,897

Segment net income (loss)(a)(b)
 
66

 
29

 
—

 
95

 
(16
)
 
2

 
81

Total assets at March 31, 2013
 
$
58,752

 
$
3,858

 
$
(109
)
 
$
62,501

 
$
1,075

 
$
(302
)
 
$
63,274

Three Months Ended March 31, 2012:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
3,449

 
$
254

 
$
(114
)
 
$
3,589

 
$
38

 
$
(23
)
 
$
3,604

Segment net income (loss)(a)
 
339

 
29

 
1

 
369

 
2

 
(3
)
 
368

Total assets at December 31, 2012
 
$
58,600

 
$
3,780

 
$
(129
)
 
$
62,251

 
$
1,116

 
$
(218
)
 
$
63,149

(a) After dividends on preferred and preference stock of subsidiaries.
(b) Segment net income (loss) for the three months ended March 31, 2013 includes a $540.0 million pre-tax charge ($333.5 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Products and Services
 
 
Electric Utilities' Revenues

 
Retail
 
Wholesale
 
Other
 
Total
 
 
(in millions)
Three Months Ended March 31, 2013
 
$
3,298

 
$
432

 
$
155

 
$
3,885

Three Months Ended March 31, 2012
 
3,092

 
349

 
148

 
3,589




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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

2013
 


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)
January 1 -
January 31
 
—

 
N/A
 
N/A
 
N/A
February 1 -
February 28
 
—

 
N/A
 
N/A
 
N/A
March 1 -
March 31
 
—

 
N/A
 
N/A
 
 
Total
 
—

 
N/A
 
N/A
 
N/A

(a)
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. As of December 31, 2012, Southern Company had repurchased a total of 9,439,561 shares under this program. In January 2013, Southern Company announced that it plans to continue this program through 2015. There were no repurchases under this program in the first quarter 2013. Pursuant to approval by the Southern Company Board of Directors, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, in accordance with applicable securities laws.


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Item 5. Other Information
In December 2011, the Financial Accounting Standards Board (FASB) issued new guidance addressing balance sheet offsetting of financial instruments and derivative instruments. Under this guidance, companies are required to report gross and net information for recognized derivative instruments and financial instruments eligible for offset under existing GAAP or subject to enforceable master netting arrangements. The FASB also issued guidance in January 2013 to clarify the scope of the new requirement, narrowing its focus to derivative instruments, security lending and borrowing agreements, and repurchase and reverse repurchase arrangements. Although new disclosures are required to present the effect or potential effect of offset related to such instruments, the existing accounting guidance allowing (but not requiring) balance sheet offsetting remains unchanged.
Southern Company and each subsidiary registrant adopted the new guidance retrospectively on January 1, 2013. The table below reflects each registrant's retrospective application of this guidance at December 31, 2011. The retrospective application did not have a material impact on the financial condition or results of operations of Southern Company or any of its subsidiary registrants. See Note (H) to the Condensed Financial Statements under "Balance Sheet Offsetting" herein for additional information.

 
Asset Derivative Contracts at December 31, 2011 (Unaudited)
 
Fair Value
 
Southern Company
Alabama Power
Georgia Power
Gulf Power
Mississippi Power
Southern Power
 
(millions)
Assets
 
 
 
 
 
 
Energy-related derivatives
 
 
 
 
 
 
Net amounts of assets presented in the Balance Sheet (a)
$
14

$
—

$
13

$
—

$
—

$
1

Gross amounts not offset in the Balance Sheet (b)
(14
)
—

(13
)
—

—

(1
)
Net energy-related derivatives
$
—

$
—

$
—

$
—

$
—

$
—

Interest rate derivatives
 
 
 
 
 
 
Net amounts of assets presented in the Balance Sheet (a)
$
13

$
—

$
—

$
—

$
—

$
—

Gross amounts not offset in the Balance Sheet (b)
—

—

—

—

—

—

Net interest rate derivatives
$
13

$
—

$
—

$
—

$
—

$
—

Foreign currency derivatives
 
 
 
 
 
 
Net amounts of assets presented in the Balance Sheet (a)
$
2

$
—

$
—

$
—

$
2

$
—

Gross amounts not offset in the Balance Sheet (b)
(2
)
—

—

—

(2
)
—

Net foreign currency derivatives
—

—

—

—

—

—

Total Net Derivative Assets
$
13

$
—

$
—

$
—

$
—

$
—

(a) None of the registrants offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheet and any cash/financial collateral pledged or received.


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Liability Derivative Contracts at December 31, 2011 (Unaudited)
 
Fair Value
 
Southern Company
Alabama Power
Georgia Power
Gulf Power
Mississippi Power
Southern Power
 
(millions)
Liability
 
 
 
 
 
 
Energy-related derivatives
 
 
 
 
 
 
Net amounts of liabilities presented in the Balance Sheet (a)
$
245

$
48

$
95

$
41

$
51

$
10

Gross amounts not offset in the Balance Sheet (b)
(14
)
—

(13
)
—

—

—

Net energy-related derivatives
$
231

$
48

$
82

$
41

$
51

$
10

Interest rate derivatives
 
 
 
 
 
 
Net amounts of liabilities presented in the Balance Sheet (a)
$
33

$
18

$
—

$
—

$
15

$
—

Gross amounts not offset in the Balance Sheet (b)
—

—

—

—

—

—

Net interest rate derivatives
$
33

$
18

$
—

$
—

$
15

$
—

Foreign currency derivatives
 
 
 
 
 
 
Net amounts of liabilities presented in the Balance Sheet (a)
$
3

$
—

$
—

$
—

$
3

$
—

Gross amounts not offset in the Balance Sheet (b)
(2
)
—

—

—

(2
)
—

Net foreign currency derivatives
1

—

—

—

1

—

Total Net Derivative Liabilities
$
265

$
66

$
82

$
41

$
67

$
10

(a) None of the registrants offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheet and any cash/financial collateral pledged or received.


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Item 6.    Exhibits.
(4) Instruments Describing Rights of Security Holders, Including Indentures
 
 
 
Georgia Power
 
 
 
 
(c)1
-
Fiftieth Supplemental Indenture to Senior Note Indenture dated as of March 15, 2013, providing for the issuance of the Series 2013A 4.30% Senior Notes due March 15, 2043. (Designated in Form 8-K dated March 12, 2013, File No. 1-6468, as Exhibit 4.2(a).)
 
 
 
(c)2
-
Fifty-First Supplemental Indenture to Senior Note Indenture dated as of March 15, 2013, providing for the issuance of the Series 2013B Floating Rate Senior Notes due March 15, 2016. (Designated in Form 8-K dated March 12, 2013, File No. 1-6468, as Exhibit 4.2(b).)
(10) Material Contracts
 
 
 
Southern Company
 
 
 
(a)1
-
Base Salaries of Named Executive Officers.
 
 
 
(a)2
-
Letter Agreement between Southern Company and Stephen E. Kuczynski dated June 4, 2011 regarding the terms of an offer of employment.
 
 
 
(a)3
-
Retention and Restricted Stock Unit Award Agreement between Southern Nuclear and Stephen E. Kuczynski effective as of July 11, 2011.
 
 
 
Georgia Power
(c)1
-
Base Salaries of Named Executive Officers.
 
 
 
(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, 2012, 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, 2012, 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, 2012, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)
 
 
 
(c)2
-
Power of Attorney for W. Ron Hinson.
 
 
 
Gulf Power
 
 
 
 
(d)1
-
Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2012, File No. 001-31737 as Exhibit 24(d) 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, 2012, 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, 2012, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)
 
 
 
 
 
 
 

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

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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: May 10, 2013

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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: May 10, 2013

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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
 
W. Ron Hinson
 
 
Executive Vice President, Chief Financial Officer, Treasurer, and Comptroller
 
 
(Principal Financial Officer)
 
 
 
 
By
 
/s/ Melissa K. Caen
 
 
 
(Melissa K. Caen, Attorney-in-fact)
 
Date: May 10, 2013

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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: May 10, 2013

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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: May 10, 2013

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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: May 10, 2013

178