Alabama Power Company Annual Report 2013

FY2013 Annual Report · Alabama Power Company

Loading PDF…

ALABAMA POWER COMPANY

2013 ANNUAL REPORT

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Alabama Power Company 2013 Annual Report

The management of Alabama Power Company (the Company) is responsible for establishing and maintaining an adequate
system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange
Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control
system are met.

Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial
reporting was conducted based on the framework in Internal Control—Integrated Framework (1992) issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the
Company's internal control over financial reporting was effective as of December 31, 2013.

Charles D. McCrary
President and Chief Executive Officer

Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer

February 27, 2014

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
Alabama Power Company

We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the Company)
(a wholly owned subsidiary of The Southern Company) as of December 31, 2013 and 2012, and the related statements of
income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended
December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit
of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements (pages 27 to 74) present fairly, in all material respects, the financial position of
Alabama Power Company as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United
States of America.

Birmingham, Alabama
February 27, 2014

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 2013 Annual Report

OVERVIEW

Business Activities

Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail and wholesale
customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the
Southeast.

Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include
the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and
to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand
growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major
storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the
Company for the foreseeable future.

Key Performance Indicators

The Company 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. The Company's financial success
is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high
reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the
Company's results.

Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient
generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of
hours of forced outages by total generation hours. The fossil/hydro 2013 Peak Season EFOR was better than the target.
Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance
targets for reliability are set internally based on historical performance. The performance for 2013 was better than the target for
these reliability measures.

Net income after dividends on preferred and preference stock is the primary measure of the Company's financial performance.
The Company's 2013 results compared to its targets for some of these key indicators are reflected in the following chart:

Key Performance Indicator

Customer Satisfaction
Peak Season EFOR — fossil/hydro

2013
Target
Performance
Top quartile in
customer surveys
5.86% or less

2013
Actual
Performance

Top quartile
3.27%

Net Income After Dividends on Preferred and Preference Stock

$694 million

$712 million

See RESULTS OF OPERATIONS herein for additional information on the Company's financial performance.

Earnings

The Company's 2013 net income after dividends on preferred and preference stock of $712 million increased $8 million (1.1%)
from the prior year. The increase in net income was due primarily to more favorable weather-related revenues in 2013 compared
to 2012, an increase in allowance for funds used during construction (AFUDC) resulting from increased capital expenditures, and
a decrease in interest expense resulting from lower interest rates. The factors increasing net income were partially offset by a
decrease in revenues related to net investment under rate certificated new plant environmental (Rate CNP Environmental) and a
decrease in wholesale revenues to municipalities.

The Company's 2012 net income after dividends on preferred and preference stock of $704 million decreased $4 million (0.6%)
from the prior year. The decrease was due to decreases in weather-related revenues due to milder weather in 2012 compared to
2011 and an increase in other operations and maintenance expenses. The factors decreasing net income were partially offset by
increases in revenues associated with the elimination of a tax-related adjustment under the Company's rate structure effective in
the fourth quarter 2011 and an increase in retail sales growth.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

RESULTS OF OPERATIONS

A condensed income statement for the Company follows:

Operating revenues

Fuel

Purchased power

Other operations and maintenance

Depreciation and amortization

Taxes other than income taxes

Total operating expenses
Operating income
Allowance for equity funds used during construction
Interest income
Interest expense, net of amounts capitalized
Other income (expense), net

Income taxes

Net income

Dividends on preferred and preference stock

Amount

2013

Increase (Decrease)
from Prior Year

2013
(in millions)

2012

5,618

1,631

229

1,289

645

348

4,142
1,476
32
16
259
(36)
478

751

128
(26)
2

118
(20)
13
—
(28)
(12)
1

—

(182)
(176)
(16)
25

1
(164)
(18)
(3)
(2)
(12)
6
(1)
(4)
—
(4)

Net income after dividends on preferred and preference stock

712

Operating Revenues

Operating revenues for 2013 were $5.6 billion, reflecting a $98 million increase from 2012. Details of operating revenues were as
follows:

Retail — prior year

Estimated change resulting from —

Rates and pricing

Sales growth

Weather

Fuel and other cost recovery

Retail — current year

Wholesale revenues —

Non-affiliates

Affiliates

Total wholesale revenues

Other operating revenues

Total operating revenues

Percent change

Amount

2013

2012

(in millions)

4,933

4,972

(18)

4,952

248

212

460

206

(115)

(54)

4,933

277

111

388

199

5,618

5,520

1.8%

(3.2)%

Retail revenues in 2013 were $5.0 billion. These revenues increased $19 million (0.4%) in 2013 and decreased $39 million (0.8%)
in 2012, each as compared to the prior year. The increase in 2013 was due to more favorable weather, increased fuel revenues and

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

increased revenues associated with rate certificated new plant (Rate CNP PPA). The increase in 2013 was partially offset by a
reduction in revenues related to net investments under Rate CNP Environmental. The decrease in 2012 was due to milder weather,
a reduction in revenues related to net investments under Rate CNP Environmental, and a reduction in fuel revenues when
compared to 2011. The decrease in 2012 was partially offset by increased revenues associated with the elimination of a tax-related
adjustment under the Company's rate structure and weather adjusted sales growth due to higher demand. See FUTURE
EARNINGS POTENTIAL – "PSC Matters" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for
additional information. See "Energy Sales" for a discussion of changes in the volume of energy sold, including changes related to
sales growth (decline) and weather.

Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel
revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased
power expenses. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Energy Cost Recovery" herein and Note 3 to
the financial statements under "Retail Regulatory Matters – Retail Energy Cost Recovery" for additional information.

Wholesale revenues from power sales to non-affiliated utilities were as follows:

Capacity and other
Energy

Total non-affiliated

2013

2012
(in millions)

2011

128
120
248

143
134
277

148
139
287

Wholesale revenues from sales to non-affiliates will vary depending on the market prices of available wholesale energy compared
to the cost of the Company'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 2013, wholesale revenues from sales to non-affiliates decreased $29 million (10.5%) reflecting a $15 million decrease in
capacity revenues and a $14 million decrease in revenues from energy sales. In 2013, kilowatt-hour (KWH) sales decreased
11.3% primarily from decreased sales to municipalities, partially offset by an 0.8% increase in the price of energy. In 2012,
wholesale revenues from sales to non-affiliates decreased $10 million (3.5%) reflecting a $5 million decrease in revenue from
energy sales and a $5 million decrease in capacity revenues. In 2012, the price of energy decreased 5.2%, partially offset by a
1.8% increase in KWH sales. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates.
These opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to
produce the energy.

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 and purchases are made in accordance with the Intercompany Interchange
Contract (IIC), as approved by the Federal Energy Regulatory Commission (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 the Company's energy cost recovery clauses.

In 2013, wholesale revenues from sales to affiliates increased $101 million (91.0%) primarily due to a $103 million increase in
energy sales, partially offset by a $2 million decrease in capacity revenues. In 2013, KWH sales increased 88.9% and there was a
1.3% increase in the price of energy. In 2012, wholesale revenues from sales to affiliates decreased $133 million (54.5%)
primarily due to a $6 million decrease in capacity revenues and a $127 million decrease in energy sales. In 2012, KWH sales
decreased 45% and there was a 17.6% decrease in the price of energy.

In 2013, other operating revenues were $206 million compared to $199 million in 2012. The increase from prior year revenues
was not material.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2013
and the percent change by year were as follows:

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Residential

Commercial

Industrial

Other

Total retail

Wholesale —

Non-affiliates

Affiliates

Total wholesale

Total energy sales

Total
KWHs

2013
(in billions)

Total KWH
Percent Change

Weather-Adjusted
Percent Change

2013

2012

2013

2012

(1.1)%
0.5

3.4
(1.4)
1.1 %

2.6%

0.6

2.3

—

1.9%

17.9

13.9

22.9

0.2

54.9

4.1

7.3

11.4

66.3

1.7%

(0.5)

3.4

(1.4)

1.8

(10.8)

88.9

34.5

(5.6)%

(1.5)

2.3

—

(1.4)

0.6

(44.9)

(26.9)

6.3%

(5.9)%

Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the
number of customers. Retail energy sales in 2013 were 1.8% more than in 2012. Residential sales increased 1.7%, due primarily
to more favorable weather in 2013. Weather-adjusted residential sales decreased 1.1%, primarily due to a decrease in customer
demand. Commercial sales and weather-adjusted commercial sales remained relatively flat in 2013. Industrial sales increased
3.4% in 2013 as a result of an increase in demand resulting from changes in production levels primarily in the chemicals, the
primary metals, and the stone, clay, and glass sectors.

Retail energy sales in 2012 were 1.4% less than in 2011. Residential and commercial sales decreased 5.6% and 1.5%,
respectively, due primarily to milder weather in 2012. Weather-adjusted residential sales increased 2.6%, primarily due to an
increase in customer demand. Industrial sales increased 2.3% in 2012 as a result of increased customer demand, primarily in the
pipelines, primary metals, chemicals, and automotive and plastics sectors, due to a recovering economy, partially offset by
decreases in the textiles and stone, clay, and glass sectors.

See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and
wholesale revenues from sales to affiliated companies as related to changes in price and KWH sales.

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is
determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the
Company purchases a portion of its electricity needs from the wholesale market.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Details of the Company's generation and purchased power were as follows:

Total generation (billions of KWHs)

Total purchased power (billions of KWHs)

Sources of generation (percent) —

Coal

Nuclear

Gas

Hydro

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

Coal

Nuclear

Gas

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

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

2013

2012

2011

65.3

4.0

3.29

0.84

3.38
2.73

5.76

59.9

5.4

3.30

0.80

3.06
2.61

4.86

64.8

4.7

3.16

0.66

3.92
2.70

6.04

KWHs generated by hydro are excluded from the average cost of fuel, generated.

** Average cost of purchased power includes fuel purchased by the Company for tolling agreements where power is generated by the provider.

Fuel and purchased power expenses were $1.9 billion in 2013, an increase of $102 million (5.8%) compared to 2012. The increase
was primarily due to a $95 million increase in the volume of KWHs generated, a $38 million increase in the average cost of fuel,
and a $37 million increase in the average cost of purchased power. These increases were partially offset by a $68 million decrease
related to the volume of KWHs purchased.

Fuel and purchased power expenses were $1.8 billion in 2012, a decrease of $192 million (9.8%) compared to 2011. The decrease
was primarily due to a $143 million decrease related to lower KWHs generated due to milder weather in 2012 compared to 2011
and a $92 million decrease in the cost of natural gas and the average cost of purchased power, partially offset by increases in the
cost of coal and nuclear fuel.

Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally
offset by energy revenues through the Company's energy cost recovery rate mechanism (Rate ECR). The Company, along with the
Alabama Public Service Commission (PSC), continuously monitors the under/over recovered balance to determine whether
adjustments to billing rates are required. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Energy Cost
Recovery" herein and Note 3 to the financial statements under "Retail Regulatory Matters – Retail Energy Cost Recovery" for
additional information.

Fuel

Fuel expenses were $1.6 billion in 2013, an increase of $128 million (8.5%) compared to 2012. This increase was primarily due to
a 10.5% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements, and a 9.9% increase
in KWHs generated by coal. This was partially offset by a 110.9% increase in the volume of KWHs generated by hydro facilities
resulting from greater rainfall. Fuel expenses were $1.5 billion in 2012, a decrease of $176 million (10.5%) compared to 2011.
This decrease was primarily due to a 21.9% decrease in the average cost of KWHs generated by natural gas, which excludes fuel
associated with tolling agreements, and a 13.7% decrease in KWHs generated by coal, partially offset by 20.2% and 4.6%
increases in the average cost of KWHs generated by nuclear fuel and coal, respectively.

Purchased Power – Non-Affiliates

In 2013, purchased power expense from non-affiliates was $100 million, an increase of $27 million (37.0%) compared to 2012.
The increase over the prior year was primarily due to a 52.6% increase in the amount of energy purchased, partially offset by a
17.2% decrease in the average cost per KWH. In 2012 and 2011, purchased power expense from non-affiliates was $73 million.

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.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Purchased Power – Affiliates

Purchased power expense from affiliates was $129 million in 2013, a decrease of $53 million (29.1%) compared to 2012. This
decrease was primarily due to a 50.4% decrease in the amount of energy purchased, partially offset by a 42.5% increase in the
average cost per KWH. Purchased power expense from affiliates was $182 million in 2012, a decrease of $16 million (8.1%)
compared to 2011. This decrease was primarily due to a 9.6% decrease in the average cost per KWH, partially offset by a 1.7%
increase in the amount of energy purchased.

Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources
at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual
agreements, as approved by the FERC.

Other Operations and Maintenance Expenses

In 2013, other operations and maintenance expenses increased $2 million (0.22%) as compared to the prior year. The increase was
not material.

In 2012, other operations and maintenance expenses increased $25 million (2.0%) as compared to the prior year. Administrative
and general expenses increased $45 million primarily related to pension and other benefit-related expenses and injuries and
damages expenses. Nuclear production expenses increased $23 million primarily related to the amortization of nuclear outage
expenses of $35 million due to a change in the nuclear maintenance outage accounting process associated with routine refueling
activities, as approved by the Alabama PSC in 2010. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Nuclear Outage
Accounting Order" herein for additional information. The increase in nuclear production expenses was partially offset by a
decrease in operations costs related to labor expense. Other power generation expenses increased $6 million primarily related to
scheduled outage costs and maintenance costs related to increases in labor and materials expenses. Transmission and distribution
expenses decreased $32 million primarily related to a reduction in accruals to the natural disaster reserve (NDR). Steam
production expenses decreased $22 million primarily related to a change in scheduled outage maintenance. See FUTURE
EARNINGS POTENTIAL – "PSC Matters – Natural Disaster Reserve" herein for additional information.

Depreciation and Amortization

Depreciation and amortization increased $6 million (0.9%) in 2013 and $2 million (0.3%) in 2012, each as compared to the prior
year. The increase in 2013 was primarily due to an increase in depreciation related to environmental assets, additions to property,
plant, and equipment related to distribution and transmission projects, as well as the amortization of software. The increase related
to environmental assets was offset by revenues under Rate CNP Environmental. These increases were partially offset by the
deferral of certain expenses under an accounting order. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Compliance
and Pension Cost Accounting Order" herein and Note 3 to the financial statements under "Compliance and Pension Cost
Accounting Order" for additional information. The increase in 2012 was not material.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $8 million (2.4%) in 2013 and $1 million (0.3%) in 2012, each as compared to the prior
year. The increase in 2013 was primarily due to property taxes, state use tax, and increases in municipal public utility license tax
bases. The increase in 2012 was not material.

Allowance for Funds Used During Construction Equity

AFUDC equity increased $13 million (68.4%) in 2013 as compared to the prior year primarily due to increased capital
expenditures associated with environmental, steam and nuclear generating facilities, and transmission. AFUDC equity decreased
$3 million (13.6%) in 2012 as compared to the prior year primarily due to a decrease in capital expenditures associated with
general plant projects and nuclear-related fuel and facilities. These decreases were primarily offset by increases in transmission
and hydro generating facilities. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for
additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized decreased $28 million (9.8%) in 2013 and $12 million (4.0%) in 2012, each as
compared to the prior year. The decreases in 2013 and 2012 were primarily due to a decrease in interest rates and the timing of
issuances and redemptions of long-term debt.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Other Income (Expense), Net

Other income (expense), net decreased $12 million (50.0%) in 2013 as compared to the prior year primarily due to increases in
donations, partially offset by increases in non-operating income related to gains on sales of non-utility property. Other income
(expense), net increased $6 million (20.0%) in 2012 as compared to the prior year primarily due to an increase in non-operating
income of $3 million, an increase in sales of property of $2 million, and a decrease in other deductions of $1 million.

Effects of Inflation

The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of
inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse
effect of inflation on the Company's results of operations has not been substantial in recent years. See Note 3 to financial
statements under "Retail Regulatory Matters – Rate RSE" for additional information.

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its
traditional service area located in the State of Alabama in addition to wholesale customers in the Southeast. Prices for electricity
provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for
wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC.
Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING
POLICIES – "Application of Critical Accounting Policies and Estimates – Electric Utility Regulation" and "FERC Matters"
herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory
matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the
Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's
primary business of selling electricity. These factors include the Company'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 other utilities, energy conservation practiced by customers, the
price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory.
Changes in regional and global economic conditions impact sales for the Company, 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.

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 Note 3 to the financial statements under "Environmental Matters" for additional information.

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the U.S. Environmental
Protection Agency (EPA) brought civil enforcement actions in federal district court against the Company alleging violations of the
New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-
owned by Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the
best available control technologies at the affected units. The case against the Company (including claims involving a unit co-
owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting
in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a
grant of summary judgment for the Company on all remaining claims and dismissal of the case with prejudice in 2011. On
September 19, 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in
favor of the Company, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for
further proceedings.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

The Company believes it 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 this matter cannot be
determined at this time.

Environmental Statutes and Regulations

General

The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of
statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the
Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource
Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act;
the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements
involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking
provisions. Through 2013, the Company had invested approximately $3.2 billion in environmental capital retrofit projects to
comply with these requirements, with annual totals of approximately $184 million, $62 million, and $34 million for 2013, 2012,
and 2011, respectively. The Company expects that base level capital expenditures to comply with existing statutes and regulations
will total approximately $1.1 billion from 2014 through 2016, with annual totals of approximately $502 million, $443 million,
and $166 million for 2014, 2015, and 2016, respectively.

The Company continues to monitor the development of the EPA's proposed water and coal combustion residuals rules and to
evaluate compliance options. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual
Obligations" herein for the Company's anticipated incremental compliance costs related to the proposed water and coal
combustion residuals rules for 2014 through 2016. The ultimate capital expenditures and compliance costs with respect to these
proposed rules, including additional expenditures required after 2016, will be dependent on the requirements of the final rules and
regulations adopted by the EPA and the outcome of any legal challenges to these rules. See "Water Quality" and "Coal
Combustion Residuals" herein for additional information.

The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and
future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations
and regulations relating to global climate change that are promulgated, including the proposed environmental regulations
described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of
emissions allowances; and the Company's fuel mix. Compliance costs may arise from existing unit retirements, installation of
additional environmental controls, upgrades to the transmission system, and adding or changing fuel sources for certain existing
units. The ultimate outcome of these matters cannot be determined at this time.

Southern Electric Generating Company (SEGCO), a subsidiary of the Company, is jointly owned with Georgia Power. As part of
its environmental compliance strategy, SEGCO plans to add natural gas as the primary fuel source for its generating units in 2015.
The capacity of SEGCO's units is sold equally to the Company and Georgia Power through a power purchase agreement (PPA). If
such compliance costs cannot continue to be recovered through retail rates, they could have a material financial impact on the
Company's financial statements. See Note 4 to the financial statements for additional information.

Compliance with any new federal or state legislation or regulations relating to air quality, water, coal combustion residuals, global
climate change, or other environmental and health concerns could significantly affect the Company. Although new or revised
environmental legislation or regulations could affect many areas of the Company's operations, the full impact of any such changes
cannot be determined at this time. Additionally, many of the Company's commercial and industrial customers may also be affected
by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for
electricity.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company.
Since 1990, the Company has spent approximately $2.7 billion in reducing and monitoring emissions pursuant to the Clean Air
Act. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with
existing regulations, and meet new requirements.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air
Quality Standard (NAAQS). In 2008, the EPA adopted a more stringent eight-hour ozone NAAQS, which it began to implement
in 2011. In May 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone
NAAQS. All areas within the Company's service territory have achieved attainment of this standard.

The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the Company's
service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS, and the EPA has officially
redesignated some former nonattainment areas within the service territory as attainment for these standards. On January 15, 2013,
the EPA published a final rule that increases the stringency of the annual fine particulate matter standard. The new standard could
result in the designation of new nonattainment areas within the Company's service territory.

Final revisions to the NAAQS for sulfur dioxide (SO2), which established a new one-hour standard, became effective in 2010. No
areas within the Company's service territory have been designated as nonattainment under this rule. However, the EPA may
designate additional areas as nonattainment in the future, which could include areas within the Company's service territory.
Implementation of the revised SO2 standard could require additional reductions in SO2 emissions and increased compliance and
operational costs.

On February 13, 2014, the EPA proposed to delete from the Alabama State Implementation Plan (SIP) the Alabama opacity rule
that the EPA approved in 2008, which provides operational flexibility to affected units. On March 6, 2013, the U.S. Court of
Appeals for the Eleventh Circuit ruled in favor of the Company and vacated an earlier attempt by the EPA to rescind its 2008
approval. The EPA’s latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air
Act. The Company believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect
unit availability and result in increased operations and maintenance costs for affected units, including units co-owned by
Mississippi Power and units owned by SEGCO.

The Company's service territory is subject to the requirements of the Clean Air Interstate Rule (CAIR), which calls for phased
reductions in SO2 and nitrogen oxide (NOx) emissions from power plants in 28 eastern states. In 2008, the U.S. Court of Appeals
for the District of Columbia Circuit issued decisions invalidating CAIR, but left CAIR compliance requirements in place while
the EPA developed a new rule. In 2011, the EPA promulgated the Cross State Air Pollution Rule (CSAPR) to replace CAIR.
However, in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety and
directed the EPA to continue to administer CAIR pending the EPA's development of a valid replacement. Review of the U.S.
Court of Appeals for the District of Columbia Circuit's decision regarding CSAPR is currently pending before the U.S. Supreme
Court.

The EPA finalized the Clean Air Visibility Rule (CAVR) in 2005, with a goal of restoring natural visibility conditions in certain
areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of best available retrofit
technology to certain sources built between 1962 and 1977 and any additional emissions reductions necessary for each designated
area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter.

In February 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions
limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. Compliance for
existing sources is required by April 16, 2015; however, states may authorize a compliance extension of up to one year to April
16, 2016.

In August 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary
Combustion Turbines (CTs). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified
CTs (including CTs at combined cycle units), during all periods of operation, including startup and shutdown, and alter the criteria
for determining when an existing CT has been reconstructed.

On February 12, 2013, the EPA proposed a rule that would require certain states to revise the provisions of their SIPs relating to
the regulation of excess emissions at industrial facilities, including fossil-fuel fired generating facilities, during periods of startup,
shut-down, or malfunction (SSM). The EPA proposes a determination that the SSM provisions in the SIPs for 36 states, including
Alabama, do not meet the requirements of the Clean Air Act and must be revised within 18 months of the date on which the EPA
publishes the final rule. The EPA has entered into a settlement agreement requiring it to finalize the rule by June 12, 2014.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance
obligations associated with the current and proposed environmental requirements discussed above. As part of this strategy, the
Company has developed a compliance plan for the MATS rule which includes the construction of baghouses to provide an
additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other
injection technology, and the use of existing or additional natural gas capability. Additionally, certain transmission system
upgrades may be required. SEGCO, jointly owned by the Company and Georgia Power, plans to add natural gas capability.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

The impacts of the eight-hour ozone, fine particulate matter and SO2 NAAQS, the Alabama opacity rule, CAIR and any future
replacement rule, CAVR, the MATS rule, the NSPS for CTs, and the SSM rule on the Company cannot be determined at this time
and will depend on the specific provisions of recently finalized and future rules, the resolution of pending and future legal
challenges, and the development and implementation of rules at the state level. These regulations could result in significant
additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash
flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered
through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations,
cash flows, and financial condition.

Water Quality

In 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by
cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake
structures for new units at existing facilities. Compliance with the proposed rule could require changes to existing cooling water
intake structures at certain of the Company's generating facilities, and new generating units constructed at existing plants would
be required to install closed cycle cooling towers. The EPA is required to issue a final rule by April 17, 2014.

On June 7, 2013, the EPA published a proposed rule which requested 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 the Company, which could result in significant capital expenditures and compliance costs
that could affect future unit retirement and replacement decisions, depending on the specific technology requirements of the final
rule. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" for additional
information regarding estimated compliance costs for 2014 through 2016.

The impact of these proposed rules cannot be determined at this time and will depend on the specific provisions of the final rules
and the outcome of any legal challenges. These regulations could result in significant additional capital expenditures and
compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and
financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, higher costs
that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact
results of operations, cash flows, and financial condition.

Coal Combustion Residuals

The Company currently operates six electric generating plants with on-site coal combustion residuals storage facilities. In addition
to on-site storage, the Company also sells a portion of its coal combustion residuals to third parties for beneficial reuse.
Historically, individual states have regulated coal combustion residuals and the State of Alabama has its own regulatory
requirements. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface
impoundments and compliance with applicable regulations.

The EPA continues to evaluate the regulatory program for coal combustion residuals, including coal ash and gypsum, under
federal solid and hazardous waste laws. In 2010, the EPA published a proposed rule that requested comments on two potential
regulatory options for the management and disposal of coal combustion residuals: regulation as a solid waste or regulation as if
the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change
to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater
monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion residuals from
regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse
options. Environmental groups and other parties have filed lawsuits in the U.S. District Court for the District of Columbia seeking
to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion
residuals. On September 30, 2013, the U.S. District Court for the District of Columbia issued an order granting partial summary
judgment to the environmental groups and other parties, ruling that the EPA has a statutory obligation to review and revise, as
necessary, the federal solid waste regulations applicable to coal combustion residuals. On January 29, 2014, the EPA filed a
consent decree requiring the EPA to take final action regarding the proposed regulation of coal combustion residuals as solid
waste by December 19, 2014.

While the ultimate outcome of this matter cannot be determined at this time and will depend on the final form of any rules
adopted and the outcome of any legal challenges, additional regulation of coal combustion residuals could have a material impact
on the generation, management, beneficial use, and disposal of such residuals. Any material changes are likely to result in
substantial additional compliance, operational, and capital costs that could affect future unit retirement and replacement decisions.
Moreover, the Company could incur additional material asset retirement obligations with respect to closing existing storage
facilities. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs
12

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to
reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. See
FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" for additional information
regarding estimated compliance costs for 2014 through 2016.

Global Climate Issues

The EPA currently regulates greenhouse gases under the Prevention of Significant Deterioration and Title V operating permit
programs of the Clean Air Act. The legal basis for these regulations is currently being challenged in the U.S. Supreme Court. In
addition, over the past several years, the U.S. Congress has considered many proposals to reduce greenhouse gas emissions,
mandate renewable or clean energy, and impose energy efficiency standards. Such proposals are expected to continue to be
considered by the U.S. Congress. International climate change negotiations under the United Nations Framework Convention on
Climate Change are also continuing.

On January 8, 2014, the EPA published re-proposed regulations to establish standards of performance for greenhouse gas
emissions from new fossil fuel steam electric generating units. A Presidential memorandum issued on June 25, 2013 also directs
the EPA to propose standards, regulations, or guidelines for addressing modified, reconstructed, and existing steam electric
generating units by June 1, 2014.

Although the outcome of any federal, state, and international initiatives, including the EPA's proposed regulations and guidelines
discussed above, will depend on the scope and specific requirements of the proposed and final rules and the outcome of any legal
challenges and, therefore, cannot be determined at this time, additional restrictions on the Company's greenhouse gas emissions or
requirements relating to renewable energy or energy efficiency at the federal or state level could result in significant additional
compliance costs, including capital expenditures. These costs could affect future unit retirement and replacement decisions and
could result in the retirement of coal-fired generating units. Also, additional compliance costs and costs related to unit retirements
could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could
negatively impact results of operations, cash flows, and financial condition.

The EPA's greenhouse gas reporting rule requires annual reporting of carbon dioxide equivalent emissions in metric tons for a
company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2012 greenhouse
gas emissions were approximately 37 million metric tons of carbon dioxide equivalent. The preliminary estimate of the
Company's 2013 greenhouse gas emissions on the same basis is approximately 41 million metric tons of carbon dioxide
equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation and mix of fuel
sources and other factors.

FERC Matters

In 2005, the Company filed two applications with the FERC for new 50-year licenses for the Company's seven hydroelectric
developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and for the Lewis Smith and
Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expired in 2007. Since the FERC
did not act on the Company's new license applications prior to the expiration of the existing licenses, the FERC is required by law
to issue annual licenses to the Company, under the terms and conditions of the existing license, until action is taken on the new
license applications. The FERC issued annual licenses for the Coosa River developments and the Warrior River developments in
2007. These annual licenses are automatically renewed each year without further action by the FERC to allow the Company to
continue operation of the projects under the terms of the previous license while the FERC completes review of the applications
for new licenses. In 2010, the FERC issued a new 30-year license to the Company for the Warrior River developments. On March
18, 2013, following the FERC's denials of their requests for rehearing, 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.

On June 20, 2013, the FERC entered an order granting the Company's application for relicensing of the Company's seven
hydroelectric developments on the Coosa River for 30 years. On July 22, 2013, the Company filed a petition requesting rehearing
of the FERC order granting the relicense seeking revisions to several conditions of the license. The Alabama Rivers Alliance,
American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission have also filed petitions
for rehearing of the FERC order.

In 2011, the Company filed an application with the FERC to relicense the Martin Dam Project. The current Martin license expired
on June 8, 2013. Since the FERC did not act on the Company's licenses application prior to the expiration of the existing license,
the FERC issued an annual license to the Company for the Martin Dam Project on June 18, 2013.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

On August 16, 2013, the Company filed an application with the FERC to relicense the Holt Hydroelectric Project. The current
Holt license will expire on August 31, 2015.

Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC
may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain
requirements that could result in additional costs to the Company. The timing and final outcome of the Company's relicense
applications cannot be determined at this time.

PSC Matters

Retail Rate Adjustments

In 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under the Company's rate structure effective with
October 2011 billings. The elimination of this adjustment resulted in additional revenues of approximately $31 million for 2011.
In accordance with the order, the Company made additional accruals to the NDR in the fourth quarter 2011 of an amount equal to
such additional 2011 revenues. The NDR was impacted as a result of operations and maintenance expenses incurred in connection
with the 2011 storms in Alabama. See "Natural Disaster Reserve" below for additional information. The elimination of this
adjustment resulted in additional revenues of approximately $106 million for 2012.

Rate RSE

Rate stabilization and equalization plan (Rate RSE) adjustments are based on forward-looking information for the applicable
upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual
adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed equity return range, customer refunds will
be required; however, there is no provision for additional customer billings should the actual retail return fall below the allowed
equity return range. Prior to 2014, retail rates remained unchanged when the retail return on common equity (ROE) was projected
to be between 13.0% and 14.5%.

During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. On August 13, 2013
the Alabama PSC voted to issue a report on Rate RSE that found that the Company's Rate RSE mechanism continues to be just
and reasonable to customers and the Company, but recommended the Company modify Rate RSE as follows:

• Eliminate the provision of Rate RSE establishing an allowed range of ROE.

• Eliminate the provision of Rate RSE limiting the Company's capital structure to an allowed equity ratio of 45%.

• Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity
(WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE
provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

•

Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the
Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top
one-third of a designated customer value benchmark survey.

Substantially all other provisions of Rate RSE were unchanged.

On August 21, 2013, the Company filed its consent to these recommendations with the Alabama PSC. The changes became
effective for calendar year 2014. On November 27, 2013, the Company made its Rate RSE submission to the Alabama PSC of
projected data for calendar year 2014; projected earnings were within the specified WCE range and, therefore, retail rates under
Rate RSE remained unchanged for 2014. In 2012 and 2013, retail rates under Rate RSE remained unchanged from 2011. Under
the terms of Rate RSE, the maximum possible increase for 2015 is 5.00%.

Rate CNP

The Company's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating
facilities into retail service under rate certificated new plant (Rate CNP). The Company may also recover retail costs associated
with certificated PPAs under Rate CNP PPA. There was no adjustment to Rate CNP PPA in 2012. On March 5, 2013, the Alabama
PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1,
2013 through March 31, 2014. It is anticipated that no adjustment will be made to Rate CNP PPA in 2014. As of December 31,
2013, the Company had an under recovered certificated PPA balance of $18 million, all of which is included in deferred under
recovered regulatory clause revenues in the balance sheet.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

certificated a second wind PPA of approximately 200 MWs which became operational in January 2014. The terms of the wind
PPAs permit the Company to use the energy and retire the associated environmental attributes in service of its customers or to sell
environmental attributes, separately or bundled with energy. The Company has elected the normal purchase normal sale (NPNS)
scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS
exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry’s application of the NPNS exception
to certain physical forward transactions in nodal markets is currently under review by the U.S. Securities and Exchange
Commission (SEC) at the request of the electric utility industry. The outcome of the SEC’s review cannot now be determined. If
the Company is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be
recorded.

Rate CNP Environmental also allows for the recovery of the Company's retail costs associated with environmental laws,
regulations, or other such mandates. Rate CNP Environmental is based on forward-looking information and provides for the
recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and
maintenance expenses, depreciation, and a return on certain invested capital. There was no adjustment to Rate CNP
Environmental in 2012 or 2013. On August 13, 2013, the Alabama PSC approved the Company's petition requesting a revision to
Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets previously being recovered
through Rate RSE. The revenue impact as a result of this revision is estimated to be $58 million in 2014. On November 21, 2013,
the Company submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate
CNP Environmental. The filing reflected a projected unrecovered retail revenue requirement for environmental compliance of
approximately $72 million, which is to be recovered in the billing months of January 2014 through December 2014. On
December 3, 2013, the Alabama PSC issued a consent order that the Company leave in effect for 2014 the factors associated with
the Company's environmental compliance costs for the year 2013. Any unrecovered amounts associated with 2014 will be
reflected in the 2015 filing. As of December 31, 2013, the Company had an under recovered environmental clause balance of $7
million which is included in deferred under recovered regulatory clause revenues in the balance sheet.

Environmental Accounting Order

Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered
investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and
closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the
affected unit's remaining useful life, as established prior to the decision regarding early retirement. See "Environmental Matters –
Environmental Statutes and Regulations" herein for additional information regarding environmental regulations.

Compliance and Pension Cost Accounting Order

In November 2012, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain compliance-
related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in
operations expense related to pension cost for 2013. These deferred costs are to be amortized over a three-year period beginning
in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection
issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the U.S. Nuclear
Regulatory Commission (NRC), and (iii) NRC guidance addressing the readiness at nuclear facilities within the U.S. for severe
events. The compliance-related expenses to be afforded regulatory asset treatment over the five-year period are currently
estimated to be approximately $37 million. The amount of operations and maintenance expenses deferred to a regulatory asset in
2013 associated with compliance-related expenditures and pension cost was approximately $8 million and $12 million,
respectively. Pursuant to the accounting order, the Company has the ability to accelerate the amortization of the regulatory assets
with notification to the Alabama PSC. See "Other Matters" herein for information regarding NRC actions as a result of the
earthquake and tsunami that struck Japan in 2011.

Retail Energy Cost Recovery

The Company has established energy cost recovery rates under Rate ECR as approved by the Alabama PSC. Rates are based on
an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and
recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current
regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts
recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under
recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no
significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve
billing rates under Rate ECR of up to 5.910 cents per KWH. On December 3, 2013, the Alabama PSC issued a consent order that
the Company leave in effect the energy cost recovery rates which began in April 2011 for 2014. Therefore, the Rate ECR factor as

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

of January 1, 2014 remained at 2.681 cents per KWH. Effective with billings beginning in January 2015, the Rate ECR factor will
be 5.910 cents per KWH, absent a further order from the Alabama PSC.

The Company’s over recovered fuel costs at December 31, 2013 totaled $42 million as compared to under recovered fuel costs of
$4 million at December 31, 2012. At December 31, 2013, $27 million is included in other regulatory liabilities, current and $15
million is included in deferred over recovered regulatory clause revenues. The under recovered fuel costs at December 31, 2012
are included in deferred under recovered regulatory clause revenues. 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 recovery of the under recovered fuel costs.

Natural Disaster Reserve

Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover
the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate
Natural Disaster Reserve (Rate NDR) charge to customers consisting of two components. The first component is intended to
establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of
the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and
any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit
balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval,
the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and
$5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to
accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged
against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to
reliability-related expenditures as a part of an annual budget process for the following year or during the current year for
identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to
offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of
future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the
NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating
cash flows.

In accordance with the order that was issued by the Alabama PSC in 2011 to eliminate a tax-related adjustment under the
Company's rate structure that resulted in additional revenues, the Company made additional accruals to the NDR in the fourth
quarter 2011 of an amount equal to the additional 2011 revenues, which were approximately $31 million.

The accumulated balances in the NDR for the years ended December 31, 2013 and December 31, 2012 were approximately $96
million and $103 million, respectively. Any accruals to the NDR are included in the balance sheets under other regulatory
liabilities, deferred and are reflected as other operations and maintenance expenses in the statements of income.

Nuclear Outage Accounting Order

In accordance with a 2010 Alabama PSC order, nuclear outage operations and maintenance expenses for the two units at Plant
Farley are deferred to a regulatory asset when the charges actually occur and are then amortized over the subsequent 18-month
operational cycle.

Approximately $31 million of nuclear outage costs from the spring of 2012 was amortized to nuclear operations and maintenance
expenses over the 18-month period ended in December 2013. During the spring of 2013, approximately $28 million of nuclear
outage costs was deferred to a regulatory asset, and beginning in July 2013, these deferred costs are being amortized over an 18-
month period. During the fall of 2013, approximately $32 million of nuclear outage costs associated with the second unit was
deferred to a regulatory asset, and beginning in January 2014, these deferred costs are being amortized over an 18-month period.
The Company will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a
subsequent 18-month period pursuant to the Alabama PSC order.

Non-Nuclear Outage Accounting Order

On August 13, 2013, the Alabama PSC approved the Company's petition requesting authorization to defer to a regulatory asset
account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014
and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures to be deferred and
amortized are estimated to total approximately $78 million.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Income Tax Matters

Bonus Depreciation

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 extended 50% bonus depreciation for property placed in service in 2013 (and for certain
long-term production-period projects to be placed in service in 2014). The extension of 50% bonus depreciation had a positive
impact on the Company's cash flows of approximately $74 million in 2013 and is expected to have a positive impact between $40
million and $45 million on the Company's 2014 cash flows.

Other Matters

In accordance with accounting standards related to employers' accounting for pensions, the Company recorded pension costs of
$47 million in 2013 and $6 million in 2012 and recorded non-cash pre-tax pension income of $21 million in 2011. Postretirement
benefit costs for the Company were $7 million, $10 million, and $11 million in 2013, 2012, and 2011, respectively. Such amounts
are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit
costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the
regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and
postretirement benefits, see Note 2 to the financial statements.

The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In
addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company'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 residuals, 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 the Company cannot be predicted at this time; however, for
current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that
the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial
statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other
matters being litigated which may affect future earnings potential.

In 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the
Fukushima Daiichi generating plant. The events in Japan have created uncertainties that may affect future costs for operating
nuclear plants. Specifically, the NRC is performing additional operational and safety reviews of nuclear facilities in the U.S.,
which could potentially impact future operations and capital requirements. In addition, the NRC has issued a series of orders
requiring safety-related changes to U.S. nuclear facilities and expects to issue orders in the future requiring additional upgrades.
The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further
review and action by the NRC. See "PSC Matters – Compliance and Pension Cost Accounting Order" herein and Note 3 to the
financial statements under "Retail Regulatory Matters – Compliance and Pension Cost Accounting Order" for additional
information on the Company's PSC approved accounting order, which allows the deferral of certain compliance-related operations
and maintenance expenditures related to compliance with the NRC guidance.

Additionally, there are certain risks associated with the operation of nuclear generating units, including potential impacts that
could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be
determined at this time.

On November 19, 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel
depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act
of 1982 or until the U.S. Congress enacts an alternative waste management plan. In accordance with the court’s order, the DOE
has submitted a proposal to the U.S. Congress to change the fee to zero. That proposal is pending before the U.S. Congress and
will become effective after 90 days of legislative session from the time of submittal unless the U.S. Congress enacts legislation
that impacts the proposed fee change. The DOE’s petition for rehearing of the November 2013 decision is currently pending and
the Company is continuing to pay the fee of approximately $13 million annually. The ultimate outcome of this matter cannot be
determined at this time.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

The Company prepares its financial statements in accordance with generally accepted accounting principles (GAAP). Significant
accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are
made that may have a material impact on the 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. Senior
management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of
Southern Company's Board of Directors.

Electric Utility Regulation

The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. As a result, the Company
applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the
ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be
recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related
regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the
recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's
financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ
from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation,
asset retirement obligations, and pension and postretirement benefits have less of a direct impact on the Company's results of
operations and financial condition than they would on a non-regulated company.

As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management
reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on
applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact
the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.

Contingent Obligations

The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject
it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial
statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to
such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable
and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be
unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's financial statements.

Pension and Other Postretirement Benefits

The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These
assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected
salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest
and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain
unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over
future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the
Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in
assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining the Company's pension and other postretirement benefit expense in accordance with GAAP are the
expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic
benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the
Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external
actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns
on various asset classes to the Company's target asset allocation. The Company discounts the future cash flows related to its
postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for
high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a
$6 million or less change in total annual benefit expense and an $82 million or less change in projected obligations.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company's financial condition remained stable at December 31, 2013. The Company's cash requirements primarily consist of
funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other
investing activities include investments to comply with environmental regulations and for restoration following major storms.
Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 2014 through
2016, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed
operating cash flows. Projected capital expenditures in that period include investments to maintain existing generation facilities,
to add environmental equipment for existing generating units, and to expand and improve transmission and distribution facilities.
The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt and equity issuances.
The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit
arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital
Requirements and Contractual Obligations" herein for additional information.

The Company's investments in the qualified pension plan and the nuclear decommissioning trust funds increased in value as of
December 31, 2013 as compared to December 31, 2012. No contributions to the qualified pension plan were made for the year
ended December 31, 2013. The Company's funding obligations for the nuclear decommissioning trust fund are based on the site
study, and the next study is expected to be conducted in 2018.

Net cash provided from operating activities totaled $1.9 billion for 2013, an increase of $538 million as compared to 2012. The
increase in cash provided from operating activities was primarily due to changes in timing of fossil fuel stock purchases and
payment of accounts payable, and collection of fuel cost recovery revenues. Net cash provided from operating activities totaled
$1.4 billion for 2012, a decrease of $672 million as compared to 2011. The decrease in cash provided from operating activities
was primarily due to an increase in fossil fuel stock, a decrease in deferred income taxes, and the timing of income tax payments
and refunds associated with bonus depreciation.

Net cash used for investing activities totaled $1.1 billion for 2013, $0.9 billion for 2012, and $1.0 billion for 2011. In 2013, these
additions were primarily due to gross property additions related to steam generation, distribution, and transmission equipment. In
2012, these additions were primarily due to gross property additions related to nuclear fuel and transmission, distribution, and
steam generating equipment. In the prior years, gross property additions were primarily related to environmental mandates,
construction of transmission and distribution facilities, replacement of steam generation equipment, and purchases of nuclear fuel.

Net cash used for financing activities totaled $614 million in 2013 primarily due to the payment of common stock dividends, and
the issuance and a maturity of senior notes. Net cash used for financing activities totaled $649 million in 2012 primarily due to
issuances, redemptions, and a maturity of senior notes, and payment of common stock dividends to Southern Company. Net cash
used for financing activities totaled $869 million in 2011 primarily due to issuances, redemptions, and a maturity of debt
securities and payment of higher 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 2013 include an increase of $620 million in property, plant, and equipment primarily due to
additions to steam, distribution, and transmission facilities. Other significant changes include an increase of $276 million in
prepaid pension costs and a decrease of $391 million in other regulatory assets, deferred, both of which are primarily attributable
to a positive return on assets and an increase in the discount rate associated with retirement benefit plans.

The Company's ratio of common equity to total capitalization, including short-term debt, was 44.3% in 2013 and 44.0% in 2012.
See Note 6 to the financial statements for additional information.

Sources of Capital

The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the
past. The Company 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 prevailing market conditions, regulatory approval, and other factors.

Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of
securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of
securities authorized by the Alabama PSC are continuously monitored and appropriate filings are made to ensure flexibility in the
capital markets.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under
"Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or
money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company
system.

The Company's current liabilities sometimes exceed current assets because of the Company'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 December 31, 2013, the Company had approximately $295 million of cash and cash equivalents. Committed credit
arrangements with banks at December 31, 2013 were as follows:

Expires(a)

2014

2015

2018

Total

Unused

(in millions)

Executable
Term-Loans

One
Year

Two
Years

Due Within One Year
Not Term
Out

Term Out

238

1,030

1,303

— $

185

(a) No credit arrangements expire in 2016 or 2017.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

Most of these arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness
(including guarantee obligations) of the Company. Such cross default provisions to other indebtedness would trigger an event of
default if the Company defaulted on indebtedness or guarantee obligations over a specified threshold. The Company is currently
in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of
borrowings. The Company expects to renew its credit arrangements as needed, prior to expiration.

In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including a
commercial paper program, to meet liquidity needs. A portion of the unused credit with banks is allocated to provide liquidity
support to the Company's variable rate pollution control revenue bonds and commercial paper borrowings. As of December 31,
2013, the Company had $793 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In
addition, at December 31, 2013, the Company had $200 million of fixed rate pollution control revenue bonds that will be required
to be remarketed within the next 12 months.

The Company may meet short-term cash needs through its commercial paper program. The Company 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 the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are
loaned directly to the Company. 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 the
End of the Period

Weighted
Average
Interest
Rate

Amount
Outstanding
(in millions)

Short-term Debt During the Period (a)
Weighted
Average
Interest
Rate

Maximum
Amount
Outstanding
(in millions)

Average
Outstanding
(in millions)

December 31, 2013:

Commercial paper

December 31, 2012:

Commercial paper

December 31, 2011:

Commercial paper

$—

—%

$11

$20

0.2%

$90

$57

$255

(a) Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2013, 2012, and 2011.

Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of
credit, and cash.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Financing Activities

In November 2013, the Company's $250 million aggregate principal amount of its Series 2008B 5.80% Senior Notes due
November 15, 2013 matured.

In December 2013, the Company issued $300 million aggregate principal amount of its Series 2013A 3.55% Senior Notes due
December 1, 2023. The proceeds were used for general corporate purposes, including the Company's continuous construction
program.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company 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.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as
a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the
event of a credit rating change 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 December 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 Southern Company system power
pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern
Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company's ability to
access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On May 24, 2013, Standard and Poor's Rating Services, a division of the McGraw Hill Companies Inc. (S&P), revised the ratings
outlook for Southern Company and the traditional operating companies, including the Company, from stable to negative.

On January 31, 2014, Moody's Investors Service, Inc. (Moody's) upgraded the senior unsecured debt and preferred stock ratings
of the Company to A1 from A2 and A3 from Baa1, respectively. Moody's maintained the stable ratings outlook for the Company.

Market Price Risk

Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure
to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these
exposures, the 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 Company's policies in areas such as counterparty exposure and risk
management practices. The 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.

To mitigate future exposure to changes in interest rates, the Company enters into derivatives that have been designated as hedges.
The weighted average interest rate on $984 million of long-term variable interest rate exposure that has not been hedged at
January 1, 2014 was 0.72%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate
long-term debt, the change would affect annualized interest expense by approximately $10 million at January 1, 2014. See Note 1
to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.

To mitigate residual risks relative to movements in electricity prices, the Company 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. The Company continues to manage a retail fuel-hedging program implemented per the guidelines of the
Alabama PSC. The Company had no material change in market risk exposure for the year ended December 31, 2013 when
compared to the December 31, 2012 reporting period.

In addition, Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to
operating considerations at the Company's electric generating facilities. Rate ECR also allows recovery of the cost of financial
instruments used for hedging market price risk up to 75% of the budgeted annual amount of natural gas purchases. The Company
may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for
natural gas financial options may not exceed 5% of the Company's natural gas budget for that year.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of
natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of
which are composed of regulatory hedges, were as follows:

2013
Changes

2012
Changes

Contracts outstanding at the beginning of the period, assets (liabilities), net

Contracts realized or settled
Current period changes(a)
Contracts outstanding at the end of the period, assets (liabilities), net

Fair Value
(in millions)
(13) $
10

2
(1) $

(a)

Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The net hedge volumes of energy-related derivative contracts, for the years ended December 31 were as follows:

Commodity – Natural gas swaps

Commodity – Natural gas options

Total hedge volume

* million British thermal units (mmBtu)

2013

2012

mmBtu* Volume

(in millions)

(48)
46
(11)
(13)

The weighted average swap contract cost above market prices was approximately $0.02 per mmBtu as of December 31, 2013
and $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 the Company's retail energy cost recovery clause.

At December 31, 2013 and 2012, substantially all of the Company's energy-related derivative contracts were designated as
regulatory hedges and are related to the Company'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 energy cost
recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially
deferred in other comprehensive income 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 and were not material for any year presented.

The 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 10 to the financial statements for further discussion of fair value measurements.
The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2013
were as follows:

Level 1

Level 2

Level 3

Fair value of contracts outstanding at end of period

Fair Value Measurements
December 31, 2013

Maturity

Year 1
(in millions)

Years 2&3

— $

—

—
(3)
—
(3)

Total

Fair Value

— $
(1)
—
(1) $

The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate
derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure.
Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional
information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.

Capital Requirements and Contractual Obligations

The Company's construction program consists of a base level capital investment and capital expenditures to comply with existing
environmental statutes and regulations. Over the next three years, the Company estimates spending, as part of its base level
capital investment, $575 million on Plant Farley (including nuclear fuel), $930 million on distribution facilities, and $654 million
on transmission additions. These base level capital investment amounts also include capital expenditures related to contractual
purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Proposed water and
coal combustion residuals rules are not included in the construction program base level capital investment. The Company's base
level construction program investments including investments to comply with existing environmental statutes and regulations and
the estimated incremental compliance costs related to the proposed water and coal combustion residuals rules over the 2014
through 2016 three-year period, based on the assumption that coal combustion residuals will continue to be regulated as non-
hazardous solid waste under the proposed rule, are estimated as follows:

Construction program:

Base capital

Existing environmental statutes and regulations
Total construction program base level capital investment

Potential incremental environmental compliance investments:
Proposed water and coal combustion residuals rules

2014

2015

(in millions)

2016

1,229

502
1,731

1,210

443
1,653

911

166
1,077

143

See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" for additional
information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates
because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in
environmental 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.

In addition to the funds required for the Company's construction program, approximately $654 million will be required by the end
of 2016 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost
securities and replace these obligations with lower cost capital if market conditions permit.

As a result of NRC requirements, the Company has external trust funds for nuclear decommissioning costs; however, the
Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements
under "Nuclear Decommissioning." The Company has also established an external trust fund for postretirement benefits as
ordered by the Alabama PSC. The cumulative effect of funding these items over an extended period will diminish internally
funded capital for other purposes and may require the Company to seek capital from other sources. See Note 2 to the financial
statements for additional information.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related
interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in
the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Contractual Obligations

Long-term debt(a) —

Principal
Interest

Preferred and preference stock dividends(b)
Financial derivative obligations(c)
Operating leases(d)
Capital Lease
Purchase commitments —

Capital(e)
Fuel(f)
Purchased power(g)
Other(h)

Pension and other postretirement benefit plans(i)
Total

2014

2015-
2016

2017-
2018
(in millions)

After
2018

Total

— $
243
39
3
15
—

1,590
1,351
58
45

654
484
79
5
24
1

2,563
1,787
121
63

561
431
79
—
10
1

—
854
128
45

—

5,018
3,225
—
—
15
3

—
804
570
14

—

6,233
4,383
197
8
64
5

4,153
4,796
877
167

3,361

5,814

2,109

9,649

$ 20,933

(a) All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with
lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2014, as reflected in the
statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.

(b) Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.

(d) Excludes PPAs that are accounted for as leases and are included in purchased power.

(e) The Company provides estimated capital expenditures for a three-year period, including capital expenditures and compliance costs associated with existing
environmental regulations. Such amounts exclude the Company's estimates of potential incremental environmental compliance investment to comply with
proposed water and coal combustion residuals rules, which are approximately $3 million, $9 million, and $143 million for 2014, 2015, and 2016,
respectively. These amounts also exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service
agreements, which are reflected separately. At December 31, 2013, significant purchase commitments were outstanding in connection with the construction
program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" for additional information.

(f)

Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain
provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices
at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future
prices at December 31, 2013.

(g) Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy. Amounts are related to the

Company's certificated PPAs which include MWs purchased from gas-fired and wind-powered facilities.

(h)

Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on
inflation indices.

(i) The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory
contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension
plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan
trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension
and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other
benefit payments will be made from the Company's corporate assets.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

Cautionary Statement Regarding Forward Looking Statements

The Company's 2013 Annual Report contains forward-looking statements. Forward-looking statements include, among other
things, statements concerning retail sales, retail rates, 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, filings with state and federal regulatory authorities, impact of the ATRA, 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 residuals, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants,
including mercury, and other substances, and also changes in tax and other laws and regulations to which the Company is
subject, as well as changes in application of existing laws and regulations;

current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters, pending EPA
civil action against the Company, and Internal Revenue Service and state tax audits;

the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

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, including
from the development and deployment of alternative energy sources such as self-generation and distributed generation
technologies, and any potential economic impacts resulting from federal fiscal decisions;

available sources and costs of fuels;

effects of inflation;
ability to control costs and avoid cost overruns during the development and construction of facilities, to construct
facilities in accordance with the requirements of permits and licenses, and to satisfy any operational and environmental
performance standards;

investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;

advances in technology;

state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions
relating to fuel and other cost recovery mechanisms;

the inherent risks involved in operating nuclear generating facilities, including environmental, health, regulatory, natural
disaster, terrorism, or financial risks;

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 the Company;

the ability of counterparties of the Company 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 Company'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 the Company's
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;

the ability of the Company to obtain additional generating capacity at competitive prices;

catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, droughts, pandemic health
events such as influenzas, or other similar occurrences;

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2013 Annual Report

•

the direct or indirect effects on the Company'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) filed by the Company from time
to time with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012, and 2011
Alabama Power Company 2013 Annual Report

Operating Revenues:
Retail revenues

Wholesale revenues, non-affiliates

Wholesale revenues, affiliates

Other revenues

Total operating revenues
Operating Expenses:
Fuel

Purchased power, non-affiliates

Purchased power, affiliates
Other operations and maintenance

Depreciation and amortization

Taxes other than income taxes

Total operating expenses
Operating Income

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

Interest income

Interest expense, net of amounts capitalized

Other income (expense), net

Total other income and (expense)
Earnings Before Income Taxes

Income taxes
Net Income

Dividends on Preferred and Preference Stock

2013

2012
(in millions)

2011

4,952

4,933

4,972

248

212

206

5,618

1,631

100

129
1,289

645

348

4,142

1,476

16
(259)
(36)
(247)
1,229

478

751

277

111

199

5,520

1,503

182
1,287

639

340

4,024

1,496

16
(287)
(24)
(276)
1,220

477

743

287

244

199

5,702

1,679

198
1,262

637

339

4,188

1,514

18
(299)
(30)
(289)
1,225

478

747

708

Net Income After Dividends on Preferred and Preference Stock

712

704

The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2013, 2012, and 2011
Alabama Power Company 2013 Annual Report

Net Income

Other comprehensive income (loss):

Qualifying hedges:

2013

2012
(in millions)

2011

751

743

747

Changes in fair value, net of tax of $-, $(7), and $(5), respectively

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

Total other comprehensive income (loss)

Comprehensive Income

The accompanying notes are an integral part of these financial statements.

—

752

(11)

2
(9)
734

(9)

(2)
(11)
736

STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012, and 2011
Alabama Power Company 2013 Annual Report

Operating Activities:
Net income
Adjustments to reconcile net income
to net cash provided from operating activities —

Depreciation and amortization, total
Deferred income taxes
Allowance for equity funds used during construction
Pension, postretirement, and other employee benefits
Stock based compensation expense
Natural disaster reserve
Other, net
Changes in certain current assets and liabilities —

-Receivables
-Fossil fuel stock
-Materials and supplies
-Other current assets
-Accounts payable
-Accrued taxes
-Accrued compensation
-Retail fuel cost over recovery
-Other current liabilities
Net cash provided from operating activities
Investing Activities:
Property additions
Investment in restricted cash from pollution control bonds
Distribution of restricted cash from pollution control bonds
Nuclear decommissioning trust fund purchases
Nuclear decommissioning trust fund sales
Cost of removal net of salvage
Change in construction payables
Other investing activities
Net cash used for investing activities
Financing Activities:
Proceeds —

Capital contributions from parent company
Senior notes issuances

Redemptions —

Pollution control revenue bonds
Senior notes

Payment of preferred and preference stock dividends
Payment of common stock dividends
Other financing activities
Net cash used for financing activities
Net Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Year
Cash and Cash Equivalents at End of Year
Supplemental Cash Flow Information:
Cash paid during the period for —

Interest (net of $11, $7 and $9 capitalized, respectively)
Income taxes (net of refunds)

Noncash transactions - accrued property additions at year-end

The accompanying notes are an integral part of these financial statements.

2013

2012
(in millions)

2011

751

743

747

816
198
(32)
9
10
3
(41)

2
146
19
5
35
(23)
(23)
42
(3)
1,914

(1,107)
—
—
(280)
279
(47)
(13)
26
(1,142)

24
300

—
(250)
(39)
(644)
(5)
(614)
158
137
295

243
296
18

767
164
(19)
(21)
9
3
(27)

23
(132)
(21)
(4)
(77)
(12)
(3)
1
(18)
1,376

(867)
1
—
(194)
193
(33)
12
(46)
(934)

27
1,000

(1)
(950)
(39)
(684)
(2)
(649)
(207)
344
137

273
309
31

749
459
(22)
(41)
6
34
(41)

18
47
(33)
(6)
11
157
(12)
—
(25)
2,048

(977)
4
13
(350)
349
(28)
(9)
9
(989)

12
700

(4)
(750)
(39)
(774)
(14)
(869)
190
154
344

286
(139)
19

BALANCE SHEETS
At December 31, 2013 and 2012
Alabama Power Company 2013 Annual Report

Assets

Current Assets:
Cash and cash equivalents

Receivables —

Customer accounts receivable

Unbilled revenues

Under recovered regulatory clause revenues

Other accounts and notes receivable

Affiliated companies

Accumulated provision for uncollectible accounts

Fossil fuel stock, at average cost

Materials and supplies, at average cost

Vacation pay

Prepaid expenses

Other regulatory assets, current

Other current assets

Total current assets
Property, Plant, and Equipment:
In service

Less accumulated provision for depreciation

Plant in service, net of depreciation

Nuclear fuel, at amortized cost

Construction work in progress

Total property, plant, and equipment
Other Property and Investments:
Equity investments in unconsolidated subsidiaries

Nuclear decommissioning trusts, at fair value

Miscellaneous property and investments
Total other property and investments
Deferred Charges and Other Assets:
Deferred charges related to income taxes
Prepaid pension costs
Deferred under recovered regulatory clause revenues
Other regulatory assets, deferred
Other deferred charges and assets
Total deferred charges and other assets
Total Assets

The accompanying notes are an integral part of these financial statements.

2013

2012

(in millions)

295

137

341

142

—

54
(8)
329

375

321

138

55
(8)
475

395

1,691

1,757

22,092

8,114

13,978

332

748

21,407

7,761

13,646

354

438

15,058

14,438

714

80
848

519
276
25
692
142
1,654

605

78
736

525
—
11
1,083
162
1,781

19,251

18,712

BALANCE SHEETS
At December 31, 2013 and 2012
Alabama Power Company 2013 Annual Report

Liabilities and Stockholder's Equity

Current Liabilities:
Securities due within one year

Accounts payable —

Affiliated

Other

Customer deposits

Accrued taxes —

Accrued income taxes

Other accrued taxes

Accrued interest

Accrued vacation pay

Accrued compensation

Other regulatory liabilities, current

Other current liabilities

Total current liabilities

Long-Term Debt (See accompanying statements)
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes

Deferred credits related to income taxes

Accumulated deferred investment tax credits

Employee benefit obligations

Asset retirement obligations

Other cost of removal obligations

Other regulatory liabilities, deferred

Deferred over recovered regulatory clause revenues

Other deferred credits and liabilities

Total deferred credits and other liabilities
Total Liabilities

Redeemable Preferred Stock (See accompanying statements)
Preference Stock (See accompanying statements)

Common Stockholder's Equity (See accompanying statements)
Total Liabilities and Stockholder's Equity

Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

2013

2012

(in millions)

— $

198

339

932

6,233

3,603

133

195

730

828

259

5,899
13,064

342

343

5,502

19,251

250

191

318

1,143

5,929

3,404

141

321

589

759

183

—

5,557
12,629

342

343

5,398

18,712

STATEMENTS OF CAPITALIZATION
At December 31, 2013 and 2012
Alabama Power Company 2013 Annual Report

Long-Term Debt:
Long-term debt payable to affiliated trusts —

Variable rate (3.35% at 1/1/14) due 2042

Long-term notes payable —

5.80% due 2013

0.55% due 2015

5.20% due 2016

5.50% to 5.55% due 2017

3.375% to 6.125% due 2019-2042

Total long-term notes payable

Other long-term debt —

Pollution control revenue bonds —

0.40% to 5.00% due 2034

Variable rate (0.04% at 1/1/14) due 2015

Variable rates (0.09% to 0.10% at 1/1/14) due 2017

Variable rates (0.02% to 0.13% at 1/1/14) due 2021-2038

Total other long-term debt

Capitalized lease obligations

Unamortized debt premium (discount), net

Total long-term debt (annual interest requirement — $243 million)

Less amount due within one year

Long-term debt excluding amount due within one year

2013

2012

2013

2012

(in millions)

(percent of total)

206

—

400

200

525

3,750

4,875

367

694

1,151

5
(4)
6,233

—

6,233

250

400

200

525

3,450

4,825

367

694

1,151

—
(3)
6,179

250

5,929

50.2%

49.4%

STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2013 and 2012
Alabama Power Company 2013 Annual Report

Redeemable Preferred Stock:

Cumulative redeemable preferred stock

$100 par or stated value — 4.20% to 4.92%

Authorized — 3,850,000 shares

Outstanding — 475,115 shares

$1 par value — 5.20% to 5.83%

Authorized — 27,500,000 shares

Outstanding — 12,000,000 shares: $25 stated value

(annual dividend requirement — $18 million)

Total redeemable preferred stock
Preference Stock:

Authorized — 40,000,000 shares

Outstanding — $1 par value — 5.63% to 6.50%

— 14,000,000 shares

(non-cumulative) $25 stated value

(annual dividend requirement — $21 million)

Common Stockholder's Equity:

Common stock, par value $40 per share —

Authorized: 40,000,000 shares

Outstanding: 30,537,500 shares

Paid-in capital

Retained earnings

Accumulated other comprehensive income (loss)

Total common stockholder's equity
Total Capitalization

The accompanying notes are an integral part of these financial statements.

2013

2012

2013

2012

(in millions)

(percent of total)

294

342

294

342

2.7

2.8

343

2.8

2.9

1,222

2,262

2,044
(26)
5,502

1,222

2,227

1,976
(27)
5,398

44.3

12,420

12,012

100.0%

44.9

100.0%

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2013, 2012, and 2011
Alabama Power Company 2013 Annual Report

Balance at December 31, 2010

Net income after dividends on preferred
and preference stock

Capital contributions from parent company

Other comprehensive income (loss)

Cash dividends on common stock
Balance at December 31, 2011

Net income after dividends on preferred
and preference stock

Capital contributions from parent company
Other comprehensive income (loss)

Cash dividends on common stock
Balance at December 31, 2012
Net income after dividends on preferred
and preference stock

Capital contributions from parent company

Other comprehensive income (loss)

Cash dividends on common stock
Balance at December 31, 2013

Number of
Common
Shares
Issued

Common
Stock

Paid-In
Capital

Retained
Earnings

(in millions)

Accumulated
Other
Comprehensive
Income (Loss)

Total

1,222

2,156

2,022

(7) $ 5,393

—

—
—

—
31

—

—
31

—

1,222

2,182

—

—
—

—
1,222

—

45
—

—
2,227

—

—
1,222

—
2,262

708

—

—
(774)
1,956

704

—
—
(684)
1,976

712

—

—
(644)
2,044

—

—
(11)
—
(18)

—

—
(9)
—
(27)

—

708

(11)

(774)

5,342

704

45
(9)

(684)
5,398

712

(644)
—
(26) $ 5,502

The accompanying notes are an integral part of these financial statements.

NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2013 Annual Report

Index to the Notes to Financial Statements

Note

8
9

Page

Summary of Significant Accounting Polices.......................................................................... 36
Retirement Benefits ................................................................................................................ 44
Contingencies and Regulatory Matters................................................................................... 54
Joint Ownership Agreements.................................................................................................. 58
Income Taxes .......................................................................................................................... 59
Financing ................................................................................................................................ 62
Commitments.......................................................................................................................... 64
Stock Compensation ............................................................................................................... 65
Nuclear Insurance ................................................................................................................... 67
Fair Value Measurements ....................................................................................................... 68
Derivatives.............................................................................................................................. 71
Quarterly Financial Information (Unaudited)......................................................................... 75

NOTES (continued)
Alabama Power Company 2013 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Alabama Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which
is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company
Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc.
(Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries.
The traditional operating companies – the Company, Georgia Power Company (Georgia Power), Gulf Power Company (Gulf
Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four
Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers
within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells
electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services
to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by
Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services
within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's
investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear
power plants, including the Company's Plant Farley.

The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable
interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary.

The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Alabama Public Service
Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the
accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data
presented in the financial statements have been reclassified to conform to the current year presentation.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated
cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology,
marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless
communications, and other services with respect to business and operations, construction management, and power pool
transactions. Costs for these services amounted to $340 million, $340 million, and $347 million during 2013, 2012, and 2011,
respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935,
as amended, were approved by the U.S. Securities and Exchange Commission (SEC). Subsequently, additional cost allocation
methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be
rendered at cost by system service companies.

The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the
Company at cost: general executive and advisory services, general operations, management and technical services, administrative
services including procurement, accounting, employee relations, systems and procedures services, strategic planning and
budgeting services, and other services with respect to business and operations. Costs for these services amounted to $211 million,
$218 million, and $215 million during 2013, 2012, and 2011, respectively.

The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi
Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its
proportionate share of non-fuel expenses, which were $13 million in 2013, $12 million in 2012, and $12 million in 2011. Also,
Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities,
which were $27 million in 2013, $28 million in 2012, and $21 million in 2011. See Note 4 for additional information.

The Company has an agreement with Gulf Power under which the Company will make transmission system upgrades to ensure
firm delivery of energy under a non-affiliate PPA. In 2009, Gulf Power entered into a PPA for the capacity and energy from a
combined cycle plant located in Autauga County, Alabama. The total cost committed by the Company related to the upgrades is
approximately $22 million in 2013 and $31 million in 2014. The Company expects to recover a majority of these costs through a
tariff with Gulf Power until 2023. The remainder of these costs will be recovered through normal rate mechanisms.

NOTES (continued)
Alabama Power Company 2013 Annual Report

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are
generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material
services to or from affiliates in 2013, 2012, or 2011.

Also, see Note 4 for information regarding the Company's ownership in, a PPA, and a gas pipeline ownership agreement with
Southern Electric Generating Company (SEGCO).

The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of
wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company
may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased
Power Agreements" for additional information.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Regulatory Assets and Liabilities

The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate
regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered
from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated
with amounts that are expected to be credited to customers through the ratemaking process.

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

Deferred income tax charges

Loss on reacquired debt

Vacation pay

Under/(over) recovered regulatory clause revenues

Fuel-hedging (realized and unrealized) losses

Other regulatory assets
Asset retirement obligations

Other cost of removal obligations

Deferred income tax credits

Fuel-hedging (realized and unrealized) gains

Nuclear outage

Natural disaster reserve

Other regulatory liabilities

Retiree benefit plans

Regulatory deferrals

Total regulatory assets (liabilities), net

2013

2012

(in millions)

519

63
(18)
8

52
(132)
(828)
(75)
(8)
51
(96)
(11)
461

525

51
(64)
(759)
(79)
(5)
33
(103)
(13)
911

—

703

Note

(a,k)

(b)

(c,j)

(d)

(e)

(f)
(a)

(a)

(e)

(d)

(h)

(d,g)

(i,j)

(l)

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(a) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized

over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following
completion of the related activities.

(b) Recovered over the remaining life of the original issue, which may range up to 50 years.

(c) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

(d) Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding ten years.

(e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon

final settlement, actual costs incurred are recovered through the energy cost recovery clause.

(f) Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the

Alabama PSC. Capitalized upon initialization of related construction projects, if applicable.

(g) Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine

reclamation and remediation liabilities will be settled following completion of the related activities.

(h) Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC.

(i) Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.

(j) Not earning a return as offset in rate base by a corresponding asset or liability.

(k)

Included in the deferred income tax charges are $20 million for 2013 and $21 million for 2012 for the retiree Medicare drug subsidy, which is recovered and
amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years.

(l) Recorded and amortized as approved by the Alabama PSC for 2015 through 2017.

In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the
Company would be required to write off to income or reclassify to accumulated other comprehensive income (OCI) related
regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be
required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair
values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional
information.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Revenues

Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other
revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal
period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy
component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs
and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance
sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors
the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on
the rate. See Note 3 under "Retail Regulatory Matters – Energy Cost Recovery" and "Retail Regulatory Matters – Rate CNP" for
additional information.

The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all
periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased
emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based
on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Nuclear Fuel Disposal Costs" for
additional information.

Income and Other Taxes

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all
significant income tax temporary differences. Investment tax credits (ITCs) utilized are deferred and amortized to income over
the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted
to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are
"more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under
"Unrecognized Tax Benefits" for additional information.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost
includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as
taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

The Company's property, plant, and equipment in service consisted of the following at December 31:

Generation

Transmission

Distribution

General

Plant acquisition adjustment

Total plant in service

2013

2012

(in millions)
$

11,314

3,287

5,934

1,545

11,110

3,137

5,714

1,434

22,092

21,407

The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and
replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with
the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders.

In 2010, the Alabama PSC approved the Company's request to stop accruing for nuclear refueling outage costs in advance of the
refueling outages when the most recent 18-month amortization cycle ended in December 2010 and to begin deferring nuclear
outage expenses. The amortization will begin after each outage has occurred and the associated outage expenses are known.

During 2011, the Company deferred $38 million of nuclear outage expenses associated with the fall 2011 outage and began the
first 18-month amortization cycle for expenses in January 2012. These expenses were fully amortized in June 2013. The

NOTES (continued)
Alabama Power Company 2013 Annual Report

Company deferred an additional $31 million of nuclear outage expenses associated with the spring 2012 outage and began the
second amortization cycle in July 2012. These expenses were fully amortized in December 2013.

During 2013, the Company deferred $28 million of nuclear outage expenses associated with the spring 2013 outage and began the
18-month amortization cycle for expenses in July 2013. The Company deferred an additional $32 million of nuclear outage
expenses associated with the fall 2013 outage and began the 18-month amortization cycle for expenses in January 2014.

The total unamortized deferred nuclear outage expense balance of $51 million is included in the 2013 balance sheet as a
regulatory asset.

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which
approximated 3.2% in 2013 and 2012, and 3.3% in 2011. Depreciation studies are conducted periodically to update the composite
rates and the information is provided to the Alabama PSC and the FERC. When property subject to composite depreciation is
retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage,
is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are
removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost
of the plant are retired when the related property unit is retired.

In 2011, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates
beginning January 2012. The study was also provided to the Alabama PSC.

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are
recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and
depreciated over the asset's useful life. The Company has received accounting guidance from the Alabama PSC allowing the
continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire.
Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The liability for asset retirement obligations primarily relates to the decommissioning of the Company's nuclear facility, Plant
Farley. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos
removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement
obligations related to certain transmission and distribution facilities and certain wireless communication towers. However,
liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations
related to these assets are indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably
estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to
support a reasonable estimation of the asset retirement obligation. The Company will continue to recognize in the statements of
income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in
accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are
recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See
"Nuclear Decommissioning" herein for additional information on amounts included in rates.

Details of the asset retirement obligations included in the balance sheets are as follows:

Balance at beginning of year

Liabilities incurred

Liabilities settled

Accretion
Cash flow revisions (a)

Balance at end of year

(a) Updated based on results from the 2013 nuclear decommissioning study

2013

2012

(in millions)

589

—
(1)
40
102

730

553

—
(1)
37
—

589

NOTES (continued)
Alabama Power Company 2013 Annual Report

Nuclear Decommissioning

The U.S. Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for
providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply
with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and
invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the
Alabama PSC, as well as the Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an
individual net worth of at least $100 million. The FERC requires the Funds' managers to exercise the standard of care in investing
that a "prudent investor" would use in the same circumstances. The FERC regulations also require that the Funds' managers may
not invest in any securities of the utility for which it manages funds or its affiliates, except for investments tied to market indices
or other mutual funds. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the
Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual
investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with
oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to
actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are
invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes
that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the
regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or OCI. Fair value
adjustments and realized gains and losses are determined on a specific identification basis.

At December 31, 2013, investment securities in the Funds totaled $713 million, consisting of equity securities of $566 million,
debt securities of $131 million, and $16 million of other securities. At December 31, 2012, investment securities in the Funds
totaled $604 million, consisting of equity securities of $438 million, debt securities of $156 million, and $10 million of other
securities. These amounts exclude receivables related to investment income and pending investment sales and payables related to
pending investment purchases.

Sales of the securities held in the Funds resulted in cash proceeds of $279 million, $193 million, and $349 million in 2013, 2012,
and 2011, respectively, all of which were reinvested. For 2013, fair value increases, including reinvested interest and dividends
and excluding the Funds' expenses, were $120 million, of which $5 million related to realized gains and $85 million related to
unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested
interest and dividends and excluding the Funds' expenses, were $70 million, of which $4 million related to realized gains and $50
million related to unrealized gains related to securities held in the Funds at December 31, 2012. For 2011, fair value increases,
including reinvested interest and dividends and excluding the Funds' expenses, were $6 million, of which $41 million related to
realized gains and $51 million related to unrealized losses related to securities held in the Funds at December 31, 2011. While the
investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term
focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing
cash flows, consistent with the nature of and purpose for which the securities were acquired.

Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama
PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the
radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed
to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the
NRC.

At December 31, the accumulated provisions for decommissioning were as follows:

External trust funds

Internal reserves

Total

2013

2012

(in millions)

713

734

604

626

NOTES (continued)
Alabama Power Company 2013 Annual Report

Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of
December 31, 2013 based on the most current study performed in 2013 for Plant Farley are as follows:

Decommissioning periods:

Beginning year

Completion year

Site study costs:

Radiated structures

Non-radiated structures

Total site study costs

2037

2076

(in millions)

1,362

1,442

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual
decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes
in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to
determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is
expected to be conducted in 2018.

Amounts previously contributed to the Funds are currently projected to be adequate to meet the decommissioning obligations.
The Company will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the
external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner
consistent with the NRC and other applicable requirements.

Allowance for Funds Used During Construction

In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which
represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated
facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered
over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not
included in calculating taxable income. All current construction costs are included in retail rates. The composite rate used to
determine the amount of AFUDC was 9.1% in 2013, 9.4% in 2012, and 9.2% in 2011. AFUDC, net of income taxes, as a percent
of net income after dividends on preferred and preference stock was 5.4% in 2013, 3.3% in 2012, and 3.9% in 2011.

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying
value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a
specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the
carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the
amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater
than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to
sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-
evaluated when circumstances or events change.

Natural Disaster Reserve

NOTES (continued)
Alabama Power Company 2013 Annual Report

related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may
designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or
during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been
designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with
the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash
investments are securities with original maturities of 90 days or less.

Materials and Supplies

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials
are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when
installed.

Fuel Inventory

Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to
inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy
cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the U.S. Environmental Protection Agency
(EPA) are included in inventory at zero cost.

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel
purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities
(included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for
additional information. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a
derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are
accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are
recoverable through the Alabama PSC-approved fuel-hedging program. This results in the deferral of related gains and losses in
OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising
from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current
period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same
counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations
and had immaterial reclaim collateral arising from derivative instruments recognized at December 31, 2013.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company
has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's
exposure to counterparty credit risk.

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result
from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists
of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.

Variable Interest Entities

The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE
that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits
from the VIE that could potentially be significant to the VIE.

The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to
an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term
debt in the balance sheets.

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is
funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No
contributions were made to the qualified pension plan during 2013. No mandatory contributions to the qualified pension plan are
anticipated for the year ending December 31, 2014. The 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, the Company provides certain medical care and life insurance benefits for retired employees through
other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Alabama PSC
and the FERC. No contributions to the other postretirement trusts are expected during the year ending December 31, 2014.

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the
measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are
presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension
plans and the other postretirement benefit plans of 5.52% and 5.41%, respectively, and an annual salary increase of 3.84%.

Discount rate:

Pension plans

Other Postretirement Benefits

Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as
follows:

Change in benefit obligation
Benefit obligation at beginning of year
Service cost
Interest cost
Benefits paid
Actuarial (gain) loss
Retiree drug subsidy
Balance at end of year
Change in plan assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at end of year
Accrued liability

2013

2012

(in millions)

490
6
19
(24)
(62)
2
431

343
61
7
(22)
389
(42) $

470
5
22
(24)
15
2
490

315
39
11
(22)
343
(147)

Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit
plans consist of the following:

Other regulatory assets, deferred
Other regulatory liabilities, deferred
Employee benefit obligations

2013

2012

(in millions)

6
(21)
(42)

89
—
(147)

NOTES (continued)
Alabama Power Company 2013 Annual Report

Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2013 and 2012 related to the other
postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the
estimated amortization of such amounts for 2014.

Prior service cost

Net (gain) loss

Net regulatory assets (liabilities)

2013

2012
(in millions)

Estimated
Amortization
in 2014

19
(34)
(15) $

—

The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years
ended December 31, 2013 and 2012 are presented in the following table:

Net regulatory assets (liabilities):

Beginning balance

Net gain

Reclassification adjustments:

Amortization of transition obligation

Amortization of prior service costs

Amortization of net gain (loss)

Total reclassification adjustments

Total change

Ending balance

2013

2012

(in millions)

89 $
(99)

—
(3)
(2)
(5)
(104)
(15) $

Components of the other postretirement benefit plans' net periodic cost were as follows:

Service cost

Interest cost

Expected return on plan assets

Net amortization

Net periodic postretirement benefit cost

2013

2012
(in millions)

2011

19
(23)
5

22
(23)
6

96
(1)

(2)
(4)
—
(6)
(7)
89

24
(25)
7

Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on
assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by
drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as
follows:

Benefit Payments

Subsidy Receipts
(in millions)

Total

2014

2015

2016

2017

2018

2019 to 2023

164

(3) $
(3)
(3)
(4)
(4)
(22)

142

NOTES (continued)
Alabama Power Company 2013 Annual Report

Benefit Plan Assets

Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable
requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's
investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets,
including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain
efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily
through diversification but also monitors and manages other aspects of risk.

The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2013 and 2012,
along with the targeted mix of assets for each plan, is presented below:

Pension plan assets:

Domestic equity

International equity

Fixed income
Special situations

Real estate investments

Private equity

Total
Other postretirement benefit plan assets:

Domestic equity

International equity

Domestic fixed income

Special situations

Real estate investments

Private equity

Total

Target

2013

2012

26%

31%

28%

23
3

23
1

27
1

100%

44%

47%

46%

—

100%

The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major
asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the
pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset
classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of
the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations
for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a
formal rebalancing program. As additional risk management, external investment managers and service providers are subject to
written guidelines to ensure appropriate and prudent investment practices.

Investment Strategies

Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement
benefit plans disclosed above:

• Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth

attributes, managed both actively and through passive index approaches.

•

International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure,
managed both actively and through passive index approaches.

• Fixed income. A mix of domestic and international bonds.

• Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of

taxes on the portfolio.

•

Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and
exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

NOTES (continued)
Alabama Power Company 2013 Annual Report

• Real estate investments. Investments in traditional private market, equity-oriented investments in real properties

(indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity. Investments in private partnerships that invest in private or public securities typically through privately-

negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

Benefit Plan Asset Fair Values

Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of
December 31, 2013 and 2012. The fair values presented are prepared in accordance with GAAP. For purposes of determining the
fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management
relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes
made to the trustee information as appropriate.

Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:

• Domestic and international equity. Investments in equity securities such as common stocks, American depositary

receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are
valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are
valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity
securities.

• Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued

based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration
certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a
specific instrument.

• TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying

investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that
are comprised of Level 1 and Level 2 securities.

• Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level
3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various
inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques
may include purchase multiples for comparable transactions, comparable public company trading multiples, and
discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of
comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair
value of partnerships is determined by aggregating the value of the underlying assets.

NOTES (continued)
Alabama Power Company 2013 Annual Report

The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements
exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment
purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are
presented in the tables below based on the nature of the investment.

As of December 31, 2013:

Assets:

Domestic equity*

International equity*

Fixed income:

U.S. Treasury, government, and agency bonds

Mortgage- and asset-backed securities

Corporate bonds

Pooled funds

Cash equivalents and other

Real estate investments

Private equity

Total

Liabilities:

Derivatives

Total

Fair Value Measurements Using

Quoted Prices
in Active
Markets
for Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

(in millions)

— $

374

287

—

219

265

156

255

123

—

593

552

156

255

123

329

149

—

261

149

410

729

1,117

2,256

—

729

(1)
1,116

—

410

(1)
2,255

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-

diversified with no significant concentrations of risk.

NOTES (continued)
Alabama Power Company 2013 Annual Report

As of December 31, 2012:

Assets:

Domestic equity*

International equity*

Fixed income:

U.S. Treasury, government, and agency bonds

Mortgage- and asset-backed securities

Corporate bonds
Pooled funds

Cash equivalents and other

Real estate investments

Private equity

Total

Fair Value Measurements Using

Quoted Prices
in Active
Markets
for Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

(in millions)

— $

304

238

—

—
—

—

175

256

135

230
104

143

—

479

494

135

231
104

144

287

155

—

1
—

—

220

155

376

610

1,076

2,062

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-

diversified with no significant concentrations of risk.

Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable
inputs for the years ended December 31, 2013 and 2012 were as follows:

2013

2012

Real Estate
Investments

Private
Equity

Real Estate
Investments

Private
Equity

Beginning balance

Actual return on investments:

Related to investments held at year end
Related to investments sold during the year
Total return on investments
Purchases, sales, and settlements
Ending balance

220

19
8
27
14
261

(in millions)

155

2
13
15
(21)
149

217

161

2
1
3
—
220

—
2
2
(8)
155

The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair
value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to
pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and
private equities, are presented in the tables below based on the nature of the investment.

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-

diversified with no significant concentrations of risk.

NOTES (continued)
Alabama Power Company 2013 Annual Report

As of December 31, 2013:

Assets:

Domestic equity*

International equity*

Fixed income:

U.S. Treasury, government, and agency bonds

Mortgage- and asset-backed securities

Corporate bonds
Pooled funds

Cash equivalents and other

Trust-owned life insurance

Real estate investments

Private equity

Total

Fair Value Measurements Using

Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

(in millions)

Total

— $

—

—
—

—

12
6

211

—

282

Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Fair Value Measurements Using

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

(in millions)

Total

— $

—

—
—

—

12
6

211

387

178

341

As of December 31, 2012:

Assets:

Domestic equity*

International equity*

Fixed income:

U.S. Treasury, government, and agency bonds

Mortgage- and asset-backed securities

Corporate bonds

Pooled funds

Cash equivalents and other

Trust-owned life insurance

Real estate investments

Private equity

Total

—

178

—

244

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-

diversified with no significant concentrations of risk.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant
unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:

Beginning balance

Actual return on investments:

Related to investments held at year end

Related to investments sold during the year

Total return on investments

Purchases, sales, and settlements

Ending balance

Employee Savings Plan

2013

2012

Real Estate
Investments

Private
Equity

Real Estate
Investments

Private
Equity

—

(in millions)

—

—
(1)
7

—

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an
85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2013,
2012, and 2011 were $20 million, $19 million, and $18 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company'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 residuals, 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 the Company cannot be predicted at this time;
however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if
any, arising from such current proceedings would have a material effect on the Company's financial statements.

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil
enforcement actions in federal district court against the Company alleging violations of the New Source Review (NSR)
provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by Mississippi Power.
These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control
technologies at the affected units. The case against the Company (including claims involving a unit co-owned by Mississippi
Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006
of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment
for the Company on all remaining claims and dismissal of the case with prejudice in 2011. On September 19, 2013, the U.S.
Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of the Company, and
the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Environmental Remediation

The Company 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 Company could incur substantial costs to clean up
properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial
statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year
presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental
remediation.

Nuclear Fuel Disposal Costs

Acting through the U.S. Department of Energy (DOE) and pursuant to the Nuclear Waste Policy Act of 1982, the U.S.
government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level
radioactive waste generated at Plant Farley. 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, the
Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.

As a result of the first lawsuit, the Company recovered approximately $17 million, representing the vast majority of the
Company's direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In April
2012, the award was credited to cost of service for the benefit of customers.

In 2008, the Company filed a second lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at
Plant Farley. Damages are being sought for the period from January 1, 2005 through December 31, 2010. Damages will continue
to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of
December 31, 2013 for any potential recoveries from the second lawsuit. The final outcome of this matter cannot be determined
at this time; however, no material impact on the Company's net income is expected.

At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through
the expected life of the plant.

Retail Regulatory Matters

Retail Rate Adjustments

Rate RSE

Rate stabilization and equalization plan (Rate RSE) adjustments are based on forward-looking information for the applicable
upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual
adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed equity return range, customer refunds
will be required; however, there is no provision for additional customer billings should the actual retail return fall below the
allowed equity return range. Prior to 2014, retail rates remained unchanged when the retail return on common equity (ROE) was
projected to be between 13.0% and 14.5%.

During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. On August 13, 2013,
the Alabama PSC voted to issue a report on Rate RSE that found that the Company's Rate RSE mechanism continues to be just
and reasonable to customers and the Company, but recommended the Company modify Rate RSE as follows:

• Eliminate the provision of Rate RSE establishing an allowed range of ROE.

• Eliminate the provision of Rate RSE limiting the Company's capital structure to an allowed equity ratio of 45%.

NOTES (continued)
Alabama Power Company 2013 Annual Report

•

Substantially all other provisions of Rate RSE were unchanged.

Rate CNP

The Company's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating
facilities into retail service under rate certificated new plant (Rate CNP). The Company may also recover retail costs associated
with certificated PPAs under rate certificated new plant (Rate CNP PPA). There was no adjustment to Rate CNP PPA in 2012. On
March 5, 2013, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for
billings for the period April 1, 2013 through March 31, 2014. It is anticipated that no adjustment will be made to Rate CNP PPA
in 2014. As of December 31, 2013, the Company had an under recovered certificated PPA balance of $18 million, all of which is
included in deferred under recovered regulatory clause revenues in the balance sheet.

In 2011, the Alabama PSC approved and certificated a PPA of approximately 200 megawatts (MWs) of energy from wind-
powered generating facilities which became operational in December 2012. In September 2012, the Alabama PSC approved and
certificated a second wind PPA of approximately 200 MWs which became operational in January 2014. The terms of the wind
PPAs permit the Company to use the energy and retire the associated environmental attributes in service of its customers or to sell
environmental attributes, separately or bundled with energy. The Company has elected the normal purchase normal sale (NPNS)
scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS
exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry's application of the NPNS exception
to certain physical forward transactions in nodal markets is currently under review by the SEC at the request of the electric utility
industry. The outcome of the SEC's review cannot now be determined. If the Company is ultimately required to record these PPAs
at fair value, an offsetting regulatory asset or regulatory liability will be recorded.

Rate certificated new plant environmental (Rate CNP Environmental) also allows for the recovery of the Company's retail costs
associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental is based on forward-looking
information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be
recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. There was no
adjustment to Rate CNP Environmental in 2012 or 2013. On August 13, 2013, the Alabama PSC approved the Company's petition
requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets
previously being recovered through Rate RSE. The revenue impact as a result of this revision is estimated to be $58 million in
2014. On November 21, 2013, the Company submitted calculations associated with its cost of complying with environmental
mandates, as provided under Rate CNP Environmental. The filing reflected a projected unrecovered retail revenue requirement
for environmental compliance of approximately $72 million, which is to be recovered in the billing months of January 2014
through December 2014. On December 3, 2013, the Alabama PSC issued a consent order that the Company leave in effect for
2014 the factors associated with the Company's environmental compliance costs for the year 2013. Any unrecovered amounts
associated with 2014 will be reflected in the 2015 filing. As of December 31, 2013, the Company had an under recovered
environmental clause balance of $7 million which is included in deferred under recovered regulatory clause revenues in the
balance sheet.

Environmental Accounting Order

Compliance and Pension Cost Accounting Order

NOTES (continued)
Alabama Power Company 2013 Annual Report

operations expense related to pension cost for 2013. These deferred costs are to be amortized over a three-year period beginning
in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection
issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the NRC, and (iii) NRC
guidance addressing the readiness at nuclear facilities within the U.S. for severe events. The compliance-related expenses to be
afforded regulatory asset treatment over the five-year period are currently estimated to be approximately $37 million. The amount
of operations and maintenance expenses deferred to a regulatory asset in 2013 associated with compliance-related expenditures
and pension cost was approximately $8 million and $12 million, respectively. Pursuant to the accounting order, the Company has
the ability to accelerate the amortization of the regulatory assets with notification to the Alabama PSC.

Retail Energy Cost Recovery

The Company has established energy cost recovery rates under the Company's energy cost recovery rate (Rate ECR) as approved
by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance.
Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual
recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts
billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the
Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates
is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating
cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per kilowatt hour
(KWH). On December 3, 2013, the Alabama PSC issued a consent order that the Company leave in effect the energy cost
recovery rates which began in April 2011 for 2014. Therefore, the Rate ECR factor as of January 1, 2014 remained at 2.681 cents
per KWH. Effective with billings beginning in January 2015, the Rate ECR factor will be 5.910 cents per KWH, absent a further
order from the Alabama PSC.

The Company's over recovered fuel costs at December 31, 2013 totaled $42 million as compared to under recovered fuel costs of
$4 million at December 31, 2012. At December 31, 2013, $27 million is included in other regulatory liabilities, current and $15
million is included in deferred over recovered regulatory clause revenues. The under recovered fuel costs at December 31, 2012
are included in deferred under recovered regulatory clause revenues in the balance sheets. 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 recovery of the under recovered fuel costs.

Natural Disaster Reserve

Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover
the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate
NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve
balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended
to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a
24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of
storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR
charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential
customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional
amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional
accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related
expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted
reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges.
Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters,
promote system reliability, and offset costs retail customers would otherwise bear.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Nuclear Outage Accounting Order

Non-Nuclear Outage Accounting Order

4. JOINT OWNERSHIP AGREEMENTS

The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating
units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold
equally to the Company and Georgia Power under a power contract. The Company and Georgia Power make payments sufficient
to provide for the operating expenses, taxes, interest expense, and ROE. The Company's share of purchased power totaled $88
million in 2013, $109 million in 2012, and $142 million in 2011 and is included in "Purchased power from affiliates" in the
statements of income. The Company accounts for SEGCO using the equity method.

In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the
purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $25 million principal amount of
pollution control revenue bonds are outstanding. The Company has guaranteed $100 million principal amount of unsecured senior
notes issued by SEGCO for general corporate purposes. These senior notes mature on December 1, 2018. The Company had
guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes, which
matured on May 15, 2013. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations
corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under
its guarantee.

At December 31, 2013, the capitalization of SEGCO consisted of $84 million of equity and $125 million of long-term debt on
which the annual interest requirement is $3 million. SEGCO paid dividends of $7 million in 2013, $14 million in 2012, and $15
million in 2011, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO's net
income.

SEGCO plans to add natural gas as the primary fuel source in 2015 for 1,000 MWs of its generating capacity. It is currently
planning, developing, and constructing the necessary natural gas pipeline. The Company, which owns and operates a generating
unit adjacent to the SEGCO generating units, has entered into a joint ownership agreement with SEGCO for the ownership of the
gas pipeline. The Company will own 14% of the pipeline with the remaining 86% owned by SEGCO. At December 31, 2013, the
Company's portion of the construction work in progress associated with the pipeline is $1 million.

NOTES (continued)
Alabama Power Company 2013 Annual Report

In addition to the Company's ownership of SEGCO and joint ownership of the natural gas pipeline, the Company's percentage
ownership and investment in jointly-owned coal-fired generating plants at December 31, 2013 were as follows:

Facility

Greene County
Plant Miller

Units 1 and 2

Total Megawatt
Capacity

Company
Ownership

Plant in
Service

500

1,320

60.00% (1)

157

91.84% (2)

1,410

575

Accumulated
Depreciation
(in millions)
91

Construction
Work in
Progress

(1) Jointly owned with an affiliate, Mississippi Power.
(2) Jointly owned with PowerSouth Energy Cooperative, Inc.

The Company has contracted to operate and maintain the jointly-owned facilities as agent for their co-owners. The Company's
proportionate share of its plant operating expenses is included in operating expenses in the statements of income and the
Company is responsible for providing its own financing.

5. INCOME TAXES

On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax
returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files a separate company income tax return
for the State of Tennessee. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's
current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than
would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally
liable for the federal tax liability.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:

Federal —

Current

Deferred

State —

Current

Deferred

Total

2013

2012
(in millions)

2011

243

160

403

262

137

399

478

477

377

397

(1)
82

478

NOTES (continued)
Alabama Power Company 2013 Annual Report

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and
their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

Deferred tax liabilities —

Accelerated depreciation

Property basis differences

Premium on reacquired debt

Employee benefit obligations

Under recovered energy clause

Regulatory assets associated with employee benefit obligations

Asset retirement obligations

Regulatory assets associated with asset retirement obligations

Other

Total

Deferred tax assets —

Federal effect of state deferred taxes

Unbilled fuel revenue

Storm reserve

Employee benefit obligations

Other comprehensive losses

Asset retirement obligations

Other

Total

Total deferred tax liabilities, net

Portion included in prepaid expenses (accrued income taxes)

Accumulated deferred income taxes

2013

2012

(in millions)

3,187

2,989

458

209

—

198

265

128

420

218

378

—

248

114

4,516

4,419

205

231

303

108

938

3,578

3,603

194

408

248

1,040

3,379

3,404

At December 31, 2013, the Company's tax-related regulatory assets to be recovered from customers were $519 million. These
assets are primarily attributable to tax benefits that flowed through to customers in prior years, to deferred taxes previously
recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest.

At December 31, 2013, the Company's tax-related regulatory liabilities to be credited to customers were $75 million. These
liabilities are primarily attributable to unamortized ITCs.

In accordance with regulatory requirements, deferred ITCs are amortized over the life of the related property with such
amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner
amounted to $8 million in each of 2013, 2012, and 2011. At December 31, 2013, all ITCs available to reduce federal income taxes
payable had been utilized.

In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed
into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after
September 8, 2010 and through 2011 (and for certain long-term production-period projects placed in service in 2012) and 50%
bonus depreciation for property placed in service in 2012 (and for certain long-term production-period projects placed in service
in 2013).

The application of the bonus depreciation provisions in these laws significantly increased deferred tax liabilities related to
accelerated depreciation in 2013, 2012, and 2011.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

Federal statutory rate

State income tax, net of federal deduction

Non-deductible book depreciation

Differences in prior years' deferred and current tax rates

AFUDC equity

Other

Effective income tax rate

The changes in the Company's 2013 and 2012 effective tax rates were not material.

Unrecognized Tax Benefits

Changes during the year in unrecognized tax benefits were as follows:

2013

2012

2011

35.0%

4.0

1.0

(0.1)

(0.9)

(0.1)

38.9%

35.0%

4.1

0.9
(0.1)
(0.5)
(0.3)
39.1%

35.0%

4.3

0.8
(0.1)
(0.6)
(0.4)
39.0%

Unrecognized tax benefits at beginning of year

Tax positions from current periods

Tax positions from prior periods

Reductions due to settlements

Balance at end of year

2013

2012
(in millions)

2011

—
(31)
—
— $

5
(4)
(2)
31

6
(17)
—

The tax positions decrease from prior periods for 2013 relates primarily to the tax accounting method change for repairs-
generation assets. See "Tax Method of Accounting for Repairs" herein for additional information.

The impact on the Company's effective tax rate, if recognized, is as follows:

Tax positions impacting the effective tax rate

Tax positions not impacting the effective tax rate
Balance of unrecognized tax benefits

2013

2012
(in millions)

2011

— $
—
— $

— $

The tax positions not impacting the effective tax rate for 2012 relate to the timing difference associated with the tax accounting
method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information.
These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Accrued interest for unrecognized tax benefits is as follows:

Interest accrued at beginning of year

Interest reclassified due to settlements

Interest accrued during the year

Balance at end of year

2013

2012
(in millions)

2011

— $
—

—
— $

1.9
(1.9)
—

— $

1.5

—

0.4

1.9

The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain
tax positions.

NOTES (continued)
Alabama Power Company 2013 Annual Report

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of
federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible
outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2011. Southern Company
has filed its 2012 federal income tax return and has received a full acceptance letter from the IRS; however, the IRS has not
finalized its audit. For tax years 2012 and 2013, Southern Company was a participant in the Compliance Assurance Process of the
IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired,
for years prior to 2007.

Tax Method of Accounting for Repairs

In 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. Additionally, on April 30, 2013, the IRS issued Revenue
Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation
assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation
assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. On September 19,
2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to
Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1,
2014. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at
this time; however, these regulations are not expected to have a material impact on the Company's financial statements.

6. FINANCING

Long-Term Debt Payable to an Affiliated Trust

The Company has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the
related equity investments and preferred security sales were loaned back to the Company through the issuance of junior
subordinated notes totaling $206 million as of December 31, 2013 and 2012, which constitute substantially all of the assets of this
trust and are reflected in the balance sheets as long-term debt payable. The Company considers that the mechanisms and
obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee
by it of the trust's payment obligations with respect to these securities. At each of December 31, 2013 and 2012, trust preferred
securities of $200 million were outstanding. See Note 1 under "Variable Interest Entities" for additional information on the
accounting treatment for this trust and the related securities.

Securities Due Within One Year

At December 31, 2013, the Company had no scheduled maturities of senior notes due within one year. At December 31, 2012, the
Company had $250 million of senior notes due within one year.

Maturities of senior notes and pollution control revenue bonds through 2018 applicable to total long-term debt are as follows:
$454 million in 2015; $200 million in 2016; and $561 million in 2017. There are no scheduled maturities in 2014 and 2018.

Pollution Control Revenue Bonds

Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of
pollution control and solid waste disposal facilities financed by funds derived from sales by public authorities of revenue bonds.
The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such
bonds. The Company incurred no obligations related to the issuance of pollution control revenue bonds in 2013. The amount of
tax-exempt pollution control revenue bonds outstanding at each of December 31, 2013 and 2012 was $1.2 billion, respectively.

Senior Notes

In December 2013, the Company issued $300 million aggregate principal amount of its Series 2013A 3.55% Senior Notes due
December 1, 2023. The proceeds of these issuances were used for general corporate purposes, including the Company's
continuous construction program.

In November 2013, the Company's $250 million aggregate principal amount of its Series 2008B 5.80% Senior Notes due
November 15, 2013 matured.

NOTES (continued)
Alabama Power Company 2013 Annual Report

At December 31, 2013 and 2012, the Company had $4.9 billion and $4.8 billion of senior notes outstanding, respectively. These
senior notes are effectively subordinated to all secured debt of the Company which amounted to approximately $153 million at
December 31, 2013.

Outstanding Classes of Capital Stock

The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and
outstanding. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the
Company's preference stock and common stock with respect to payment of dividends and voluntary and involuntary dissolution.
The preferred stock and Class A preferred stock of the Company contain a feature that allows the holders to elect a majority of the
Company's board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-
triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as
"Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The
preference stock does not contain such a provision that would allow the holders to elect a majority of the Company's board. The
Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or
involuntary dissolution.

The Company's preferred stock is subject to redemption at a price equal to the par value plus a premium. The Company's Class A
preferred stock is subject to redemption at a price equal to the stated capital. Certain series of the Company's preference stock are
subject to redemption at a price equal to the stated capital plus a make-whole premium based on the present value of the
liquidation amount and future dividends to the first stated capital redemption date and the other series of preference stock are
subject to redemption at a price equal to the stated capital. Certain series of the Company's preferred stock are subject to
redemption at the option of the Company on or after a specified date. Information for each outstanding series is in the table
below:

Preferred/Preference Stock

4.92% Preferred Stock

4.72% Preferred Stock

4.64% Preferred Stock

4.60% Preferred Stock

4.52% Preferred Stock

4.20% Preferred Stock

5.83% Class A Preferred Stock

5.20% Class A Preferred Stock

5.30% Class A Preferred Stock

5.625% Preference Stock

6.450% Preference Stock

6.500% Preference Stock

Par Value/
Stated
Capital Per
Share

Shares
Outstanding

First Call
Date

Redemption
Price Per
Share

$100

$25

80,000

50,000

60,000

100,000

50,000

135,115

1,520,000

6,480,000

4,000,000

6,000,000

2,000,000

$103.23

$102.18

$103.14

$104.20

$102.93

$105.00

8/1/2008

4/1/2009

1/1/2012

Stated Capital

* Redemption permitted any time after issuance
** Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital

Dividend Restrictions

The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

Assets Subject to Lien

The Company has granted liens on certain property in connection with the issuance of certain series of pollution control revenue
bonds with an outstanding principal amount of $153 million as of December 31, 2013. There are no agreements or other
arrangements among the Southern Company system companies under which the assets of one company have been pledged or
otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Bank Credit Arrangements

At December 31, 2013, committed credit arrangements with banks were as follows:

Expires(a)

2014

2015

2018

Total

Unused

(in millions)

Executable
Term-Loans

One
Year

Two
Years

Due Within One Year
No Term
Out

Term
Out

238

1,030

1,303

— $

185

(a) No credit arrangements expire in 2016 or 2017.

The Company expects to renew its credit agreements as needed, prior to expiration. Most of the credit arrangements require
payment of a commitment fee based on the unused portion of the commitments or the maintenance of compensating balances
with the banks. Commitment fees average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted
from withdrawal.

Most of the Company's credit arrangements with banks have covenants that limit the Company's debt to 65% of total
capitalization, as defined in the arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated
trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit
arrangements. At December 31, 2013, the Company was in compliance with the debt limit covenants.

A portion of the unused credit with banks is allocated to provide liquidity support to the Company's variable rate pollution control
revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds requiring liquidity
support was $793 million as of December 31, 2013. In addition, at December 31, 2013, the Company had $200 million of fixed
rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.

The Company borrows through commercial paper programs that have the liquidity support of committed bank credit
arrangements. The Company may also make short-term borrowings through various other arrangements with banks. At
December 31, 2013 and 2012, there was no short-term debt outstanding. At December 31, 2013, the Company had regulatory
approval to have outstanding up to $2 billion of short-term borrowings.

7. COMMITMENTS

Fuel and Purchased Power Agreements

To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term
commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2013,
2012, and 2011, the Company incurred fuel expense of $1.6 billion, $1.5 billion, and $1.7 billion, respectively, the majority of
which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will
continue to be purchased under long-term commitments.

In addition, the Company has entered into various long-term commitments for the purchase of capacity and electricity, some of
which are accounted for as operating leases. Total capacity expense under PPAs accounted for as operating leases was $30
million, $33 million, and $33 million for 2013, 2012, and 2011, respectively. Total estimated minimum long-term obligations at
December 31, 2013 were as follows:

2014
2015
2016
2017
2018
2019 and thereafter
Total commitments

Operating Lease PPAs
(in millions)

36
38
39
40
42
182
377

SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the
other Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional
operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into

NOTES (continued)
Alabama Power Company 2013 Annual Report

keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not
subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a
contracting party under these agreements.

Operating Leases

The Company has entered into rental agreements for coal railcars, vehicles, and other equipment with various terms and
expiration dates. Total rent expense was $21 million in 2013, $24 million in 2012, and $23 million in 2011. Of these amounts,
$18 million, $19 million, and $18 million for 2013, 2012, and 2011, respectively, relate to the railcar leases and are recoverable
through the Company's Rate ECR. As of December 31, 2013, estimated minimum lease payments under operating leases were as
follows:

2014
2015

2016

2017

2018

2019 and thereafter

Total

Minimum Lease Payments

Railcars

Vehicles &
Other
(in millions)

Total

12 $
10

3 $
2

—

58 $

6 $

15
12

In addition to the above rental commitments payments, the Company has potential obligations upon expiration of certain leases
with respect to the residual value of the leased property. These leases have terms expiring through 2023 with maximum
obligations under these leases of $8 million in 2014, $5 million in 2015, $4 million in 2016, and $12 million in 2019 and
thereafter. There are no maximum obligations under these leases in 2017 and 2018. At the termination of the leases, the lessee
may either exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market
value of the leased property would substantially reduce or eliminate the Company's payments under the residual value
obligations.

Guarantees

The Company has guaranteed the obligation of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which
mature in June 2019, and also $100 million of senior notes issued in November 2013, which mature in December 2018. Georgia
Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to Georgia Power's then
proportionate ownership of SEGCO's stock if the Company is called upon to make such payment under its guarantee. See Note 4
for additional information.

8. STOCK COMPENSATION

Stock Options

Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of
the Company's employees ranging from line management to executives. As of December 31, 2013, there were approximately
1,000 current and former employees of the Company participating in the stock option program, and there were 28 million shares
of Southern Company common stock remaining available for awards under the Omnibus Incentive Compensation Plan. The
prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over
a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-
line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for
retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of
grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive
Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in
control.

NOTES (continued)
Alabama Power Company 2013 Annual Report

The estimated fair values of stock options granted were derived using the Black-Scholes stock option pricing model. Expected
volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term. Southern
Company used historical exercise data to estimate the expected term that represents the period of time that options granted to
employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of
grant that covers the expected term of the stock options.

The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock
options granted:

Year Ended December 31

Expected volatility

Expected term (in years)

Interest rate

Dividend yield

Weighted average grant-date fair value

2013

16.6%

5.0

0.9%

4.4%

$2.93

2012

17.7%

5.0

0.9%

4.2%

$3.39

2011

17.5%

5.0

2.3%

4.8%

$3.23

The Company's activity in the stock option program for 2013 is summarized below:

Outstanding at December 31, 2012

Granted

Exercised

Cancelled
Outstanding at December 31, 2013
Exercisable at December 31, 2013

Shares Subject
to Option

Weighted Average
Exercise Price

6,060,552

1,319,038
(1,035,611)
(4,271)
6,339,708
4,021,541

$
$

36.02

44.07

32.74

42.88
38.23
35.29

The number of stock options vested, and expected to vest in the future, as of December 31, 2013 was not significantly different
from the number of stock options outstanding at December 31, 2013 as stated above. As of December 31, 2013, the weighted
average remaining contractual term for the options outstanding and options exercisable was approximately six years and five
years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $26 million and $25
million, respectively.

As of December 31, 2013, there was $1 million of total unrecognized compensation cost related to stock option awards not yet
vested. That cost is expected to be recognized over a weighted-average period of approximately 11 months.

For the years ended December 31, 2013, 2012, and 2011, total compensation cost for stock option awards recognized in income
was $4 million, $4 million, and $3 million, respectively, with the related tax benefit also recognized in income of $2 million, $1
million, and $1 million, respectively.

The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company's
employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital
contribution from Southern Company.

The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $11 million, $28
million, and $23 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option
exercises totaled $4 million, $11 million, and $9 million for the years ended December 31, 2013, 2012, and 2011, respectively.

Performance Shares

Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment
of the Company's employees ranging from line management to executives. The performance share units granted under the plan
vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the
end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual
months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return
(TSR) over the three-year performance period which measures Southern Company's relative performance against a group of
industry peers. The performance shares are delivered in common stock following the end of the performance period based on
Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount.

NOTES (continued)
Alabama Power Company 2013 Annual Report

The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate
the TSR of Southern Company's stock among the industry peers over the performance period. The Company recognizes
compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation
expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The
expected volatility was based on the historical volatility of Southern Company's stock over a period equal to the performance
period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance
period of the award units.

The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance
share award units granted:

Year Ended December 31

Expected volatility

Expected term (in years)

Interest rate

Annualized dividend rate
Weighted average grant-date fair value

2013

12.0%

3.0

0.4%

$1.96
$40.50

2012

16%

3.0

0.4%

$1.89
$41.99

2011

19.2%

3.0

1.4%

$1.82
$35.97

Total unvested performance share units outstanding as of December 31, 2012 were 280,536. During 2013, 141,355 performance
share units were granted, 131,581 performance share units were vested, and 5,484 performance share units were forfeited
resulting in 284,826 unvested units outstanding at December 31, 2013. In January 2014, the vested performance share award units
were converted into 39,258 shares outstanding at a share price of $41.27 for the three-year performance and vesting period ended
December 31, 2013.

For the years ended December 31, 2013, 2012, and 2011, total compensation cost for performance share units recognized in
income was $5 million, $5 million, and $3 million, respectively, with the related tax benefit also recognized in income of $2
million, $2 million, and $1 million, respectively. As of December 31, 2013, there was $6 million of total unrecognized
compensation cost related to performance share award units that will be recognized over a weighted-average period of
approximately 11 months.

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together
with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides
funds up to $13.6 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a
mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial
nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not
more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment,
excluding any applicable state premium taxes, for the Company is $255 million per incident but not more than an aggregate of
$38 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly
assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10,
2018.

The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property
damage insurance in an amount up to $500 million for members' operating nuclear generating facilities. Additionally, the
Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for nuclear losses in excess of the $500 million primary coverage. These policies have a sublimit of
$1.7 billion for non-nuclear losses.

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental
outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26
weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments
would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company
purchases limits based on the projected full cost of replacement power and has elected a 12-week deductible waiting period.

Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available
to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $43 million.

NOTES (continued)
Alabama Power Company 2013 Annual Report

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The
aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such
additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of
such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident.
Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under
the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to
cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from
customers, would be borne by the Company and could have a material effect on the Company's financial condition and results of
operations.

All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state
premium taxes.

10. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in
pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is
minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques
used for fair value measurement.

•

Level 1 consists of observable market data in an active market for identical assets or liabilities.

Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly
observable.

Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market
participant would use in pricing an asset or liability. If there is little available market data, then the Company's own
assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value
measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

NOTES (continued)
Alabama Power Company 2013 Annual Report

As of December 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

Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

(in millions)

— $

As of December 31, 2013:

Assets:

Energy-related derivatives
Nuclear decommissioning trusts:(a)

Domestic equity
Foreign equity
U.S. Treasury and government agency securities
Corporate bonds
Mortgage and asset backed securities
Other investments

Cash equivalents
Total

Liabilities:

Energy-related derivatives

392
35
—
—
—
—
236
663

— $

74
65
24
89
18
13
—
290

—
—
—
—
—
3
—
3

— $

466
100
24
89
18
16
236
956

(a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under

"Nuclear Decommissioning" for additional information.

As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the
level of the fair value hierarchy in which they fall, were as follows:

As of December 31, 2012:

Assets:

Energy-related derivatives
Nuclear decommissioning trusts:(a)

Domestic equity

Foreign equity

U.S. Treasury and government agency securities

Corporate bonds

Mortgage and asset backed securities

Other investments

Total

Liabilities:

Energy-related derivatives

Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Fair Value Measurements Using

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

(in millions)

Total

— $

291

—

319

— $

101

290

—

— $

355

101

609

(a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

NOTES (continued)
Alabama Power Company 2013 Annual Report

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 Overnight Index Swap interest rates. Interest rate 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. See Note 11 for additional information on how these
derivatives are used.

For fair value measurements of investments within the nuclear decommissioning trusts, 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 with each security
discriminately assigned a primary pricing source, based on similar characteristics. Other investments in private equity and real
estate are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager
values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of
partnerships is determined by aggregating the value of the underlying assets.

A market price secured from the primary source vendor is 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.

As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its
equivalent), as well as the nature and risks of those investments, were as follows:

As of December 31, 2013:

Nuclear decommissioning trusts:

Equity-commingled funds

Trust-owned life insurance

Cash equivalents:

Money market funds

As of December 31, 2012:

Nuclear decommissioning trusts:

Equity-commingled funds

Trust-owned life insurance

Fair Value
(in millions)

Unfunded
Commitments

Redemption
Frequency

Redemption
Notice Period

$65

110

236

$55

None

Daily/Monthly

Daily/7 Days

Daily

15 days

Not applicable

Daily/Monthly

Daily/7 days

Daily

15 days

The nuclear decommissioning trust includes investments in 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.

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 Company's investment in the money market funds.

NOTES (continued)
Alabama Power Company 2013 Annual Report

As of December 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as
follows:

Long-term debt:
2013

2012

Carrying Amount

Fair Value

(in millions)

6,228

6,179

6,534

6,899

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 the Company.

11. DERIVATIVES

The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility
attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters
into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty
exposure and risk management practices. The 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.

Energy-Related Derivatives

The Company enters 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 Company has limited exposure to market
volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the
guidelines of the Alabama PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price
volatility.

To mitigate residual risks relative to movements in electricity prices, the Company 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 Company 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 in one of three methods:

•

Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to
the Company's 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 energy cost recovery clause.

Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly
used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements
of income in the same period as the hedged transactions are reflected in earnings.

Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as
hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative
is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any
cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the
actual price of the underlying goods being delivered.

NOTES (continued)
Alabama Power Company 2013 Annual Report

At December 31, 2013, the net volume of energy-related derivative contracts for natural gas positions for the Company, together
with the longest hedge date over which it 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*
(in millions)

Longest Hedge
Date

Longest Non-Hedge
Date

2017

—

* million British thermal units (mmBtu)

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to revenue and fuel expense for the 12-
month period ending December 31, 2014 are immaterial.

Interest Rate Derivatives

The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded
directly to earnings.

At December 31, 2013, there were no interest rate derivatives outstanding.

The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending
December 31, 2014 are $3 million. The Company has deferred gains and losses that are expected to be amortized into earnings
through 2035.

Derivative Financial Statement Presentation and Amounts

At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

Derivative Category

Derivatives designated as
hedging instruments for
regulatory purposes

Energy-related derivatives:

Total derivatives designated as
hedging instruments for
regulatory purposes

Total

Asset Derivatives

Liability Derivatives

Balance Sheet
Location

2013

2012

(in millions)

Balance Sheet
Location

2013

2012

(in millions)

Other current assets

Other deferred
charges and assets

Liabilities from risk
management activities

Other deferred credits
and liabilities

All derivative instruments are measured at fair value. See Note 10 for additional information.

NOTES (continued)
Alabama Power Company 2013 Annual Report

The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported
gross on the Company'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 at December 31, 2013 and 2012 are presented in
the following tables.

Assets

Energy-related derivatives presented in
the Balance Sheet (a)
Gross amounts not offset in the Balance
Sheet (b)
Net-energy related derivative assets

Fair Value
2012

2013

(in millions)

Liabilities

(5)
2

Energy-related derivatives presented in
the Balance Sheet (a)
Gross amounts not offset in the Balance
Sheet (b)

(4)
1 Net-energy related derivative liabilities

2013

2012

(in millions)

(5)
3

(4)

(a) The Company does not 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.

At December 31, 2013 and 2012, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative
instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows:

Derivative Category

Energy-related derivatives:

Total energy-related derivative gains
(losses)

Unrealized Losses

Unrealized Gains

Balance Sheet
Location

Other regulatory
assets, current

Other regulatory
assets, deferred

Balance Sheet
Location

Other current
liabilities

Other regulatory
liabilities,
deferred

2013

2012

(in millions)

(3) $

(14)

(5)

(4)

(8) $

(18)

2013

2012

(in millions)

For the years ended December 31, 2013, 2012, and 2011, the pre-tax effect of interest rate derivatives designated as cash flow
hedging instruments on the statements of income was as follows:

Derivatives in Cash Flow
Hedging Relationships

Derivative Category

Gain (Loss) Reclassified from Accumulated OCI into
Income
(Effective Portion)

Gain (Loss) Recognized in
OCI on Derivative
(Effective Portion)

2013

2012
(in millions)

2011

Statements of Income
Location

Amount

2013

2012
(in millions)

2011

Interest rate derivatives

$ — $

(18) $

(14)

Interest expense, net of
amounts capitalized

(3) $

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2013, 2012, and 2011, the pre-tax effect of energy-related derivatives not designated as
hedging instruments on the statements of income was not material.

Contingent Features

NOTES (continued)
Alabama Power Company 2013 Annual Report

The Company's collateral posted with its derivative counterparties at December 31, 2013 was not material. However, because of
the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from
the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $9 million. 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.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in
certain agreements that could require collateral in the event that one or more Southern Company system power pool participants
has a credit rating change to below investment grade.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company
only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's
Investors Services, Inc. and Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc. or with
counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management
policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure
to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a
result of counterparty nonperformance.

NOTES (continued)
Alabama Power Company 2013 Annual Report

12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2013 and 2012 is as follows:

Quarter Ended

March 2013
June 2013
September 2013
December 2013

March 2012
June 2012
September 2012
December 2012

Operating
Revenues

Operating
Income
(in millions)

Net Income After
Dividends on
Preferred and
Preference Stock

1,308
1,392
1,604
1,314

1,216
1,377
1,637
1,290

307
357
500
312

291
390
544
271

141
173
258
140

126
185
280
113

The Company's business is influenced by seasonal weather conditions.

SELECTED FINANCIAL AND OPERATING DATA 2009-2013
Alabama Power Company 2013 Annual Report

$
$

Operating Revenues (in millions)
Net Income After Dividends
on Preferred and Preference Stock (in millions) $
Cash Dividends on Common Stock (in millions)
$
Return on Average Common Equity (percent)
Total Assets (in millions)
Gross Property Additions (in millions)
Capitalization (in millions):
Common stock equity
Preference stock
Redeemable preferred stock
Long-term debt
Total (excluding amounts due within one year)
Capitalization Ratios (percent):
Common stock equity
Preference stock
Redeemable preferred stock
Long-term debt
Total (excluding amounts due within one year)
Customers (year-end):
Residential
Commercial
Industrial
Other
Total
Employees (year-end)

$
$

2013
5,618

712
644
13.07
19,251
1,204

5,502
343
342
6,233
12,420

44.3
2.8
2.7
50.2
100.0

$
$

2012
5,520

704
684
13.10
18,712
940

5,398
343
342
5,929
12,012

44.9
2.9
2.8
49.4
100.0

$
$

2011
5,702

708
774
13.19
18,477
1,016

5,342
343
342
5,632
11,659

45.8
2.9
2.9
48.4
100.0

$
$

2010
5,976

707
586
13.31
17,994
956

5,393
343
342
5,987
12,065

44.7
2.9
2.8
49.6
100.0

2009
5,529

670
523
13.27
17,524
1,323

5,237
343
342
6,082
12,004

43.6
2.9
2.8
50.7
100.0

1,241,998
196,209
5,851
751
1,444,809
6,896

1,237,730
196,177
5,839
748
1,440,494
6,778

1,231,574
196,270
5,844
746
1,434,434
6,632

1,235,128
197,336
5,770
782
1,439,016
6,552

1,229,134
198,642
5,912
780
1,434,468
6,842

SELECTED FINANCIAL AND OPERATING DATA 2009-2013 (continued)
Alabama Power Company 2013 Annual Report

Operating Revenues (in millions):
Residential
Commercial
Industrial
Other
Total retail
Wholesale — non-affiliates
Wholesale — affiliates
Total revenues from sales of electricity
Other revenues
Total
Kilowatt-Hour Sales (in millions):
Residential
Commercial
Industrial
Other
Total retail
Wholesale — non-affiliates
Wholesale — affiliates
Total
Average Revenue Per Kilowatt-Hour (cents):
Residential
Commercial
Industrial
Total retail
Wholesale
Total sales
Residential Average Annual
Kilowatt-Hour Use Per Customer
Residential Average Annual
Revenue Per Customer
Plant Nameplate Capacity
Ratings (year-end) (megawatts)
Maximum Peak-Hour Demand (megawatts):
Winter
Summer
Annual Load Factor (percent)
Plant Availability (percent)*:
Fossil-steam
Nuclear
Source of Energy Supply (percent):
Coal
Nuclear
Hydro
Gas
Purchased power —
From non-affiliates
From affiliates

Total

2013

2,079
1,477
1,369
27
4,952
248
212
5,412
206
5,618

17,920
13,892
22,904
211
54,927
3,711
7,672
66,310

11.60
10.63
5.98
9.02
4.04
8.16

2012

2,068
1,491
1,346
28
4,933
277
111
5,321
199
5,520

17,612
13,963
22,158
214
53,947
4,196
4,279
62,422

11.74
10.68
6.07
9.14
4.58
8.52

2011

2010

2,144
1,495
1,306
27
4,972
287
244
5,503
199
5,702

18,650
14,173
21,666
214
54,703
4,330
7,211
66,244

11.50
10.55
6.03
9.09
4.60
8.31

2,283
1,535
1,231
27
5,076
465
236
5,777
199
5,976

20,417
14,719
20,622
216
55,974
8,655
6,074
70,703

11.18
10.43
5.97
9.07
4.76
8.17

2009

1,962
1,430
1,080
25
4,497
620
237
5,354
175
5,529

18,071
14,186
18,555
218
51,030
14,317
6,473
71,820

10.86
10.08
5.82
8.81
4.12
7.45

14,451

14,252

15,138

16,570

14,716

1,676

1,674

1,740

1,853

1,597

12,222

9,347
10,692
64.9

87.3
90.7

50.0
20.3
8.1
15.7

2.9
3.0
100.0

10,285
11,096
61.3

88.6
94.5

48.2
22.6
4.1
16.8

2.0
6.3
100.0

11,553
11,500
60.6

88.7
94.7

52.5
20.8
4.6
15.3

0.9
5.9
100.0

11,349
11,488
62.6

92.9
88.4

56.6
17.7
5.0
14.0

1.6
5.1
100.0

10,701
10,870
59.8

88.5
93.3

53.4
18.6
7.9
11.8

2.0
6.3
100.0

Beginning in 2012, plant availability is calculated as a weighted equivalent availability.

DIRECTORS(cid:3)AND(cid:3)OFFICERS(cid:3)
Alabama Power Company 2013 Annual Report

Directors
Whit Armstrong
Managing Member,
Creeke Capital Investments, LLC

Ralph D. Cook
City Attorney,
City of Birmingham

David J. Cooper, Sr.
Vice Chairman,
Cooper/T. Smith Corporation
Mark A. Crosswhite1
President and Chief Executive
Officer, Alabama Power Company

Thomas A. Fanning
Chairman, President, and CEO,
Southern Company

John D. Johns
Chairman, President, and CEO,
Protective Life Corporation

Patricia M. King
President,
Sunny King Automotive Group

James K. Lowder
Chairman,
The Colonial Company
Charles D. McCrary1,2
Chairman,
Alabama Power Company

Malcolm Portera
Retired Chancellor,
The University of Alabama
System

Robert D. Powers
President,
The Eufaula Agency, Inc.

C. Dowd Ritter
Retired Chairman and CEO,
Regions Financial Corporation

James H. Sanford
Chairman,
HOME Place Farms, Inc.

John Cox Webb, IV
President,
Webb Lumber Company, Inc.

Officers
Charles D. McCrary1,2
Chairman

Mark A. Crosswhite1
President and Chief Executive
Officer

Philip C. Raymond
Executive Vice President, Chief
Financial Officer, and Treasurer

Zeke W. Smith
Executive Vice President

Steven R. Spencer
Executive Vice President

James P. Heilbron
Senior Vice President and Senior
Production Officer

Gordon G. Martin
Senior Vice President and General
Counsel

Gregory J. Barker
Senior Vice President

Anita Allcorn-Walker
Vice President and Comptroller
William E. Zales, Jr.3
Vice President, Corporate
Secretary, and Assistant Treasurer
Kathleen S. King4
Vice President, Chief Information
Officer
C. David Cox5
Vice President
Ronald Q. Patterson6
Vice President and Assistant
Treasurer

Matthew W. Bowden
Vice President

Mark S. Crews
Vice President

Daniel K. Glover
Vice President
`
R. Myrk Harkins
Vice President

John O. Hudson III
Vice President

Richard O. Hutto
Vice President

Stacy R. Kilcoyne
Vice President

Barbara J. Knight
Vice President

R. Scott Moore
Vice President

Kenneth F. Novak
Vice President
Jonathan K. Porter7
Vice President

Quentin P. Riggins
Vice President

Leslie L. Sanders
Vice President

R. Michael Saxon
Vice President

Don A. Scivley
Vice President

Julia H. Segars
Vice President

Nicholas C. Sellers
Vice President
Donna D. Smith8
Vice President

Robert L. Weaver
Vice President
Ceila H. Shorts6
Corporate Secretary
Wendy M. Hoomes6
Assistant Comptroller

Melissa K. Caen
Assistant Secretary and
Assistant Treasurer
Amy E. Blankenship6
Assistant Secretary
Kay I. Worley9
Assistant Secretary

Christopher R. Blake
Assistant Treasurer

Effective 3/2014

2 Resigned as President and
Chief Executive Officer
effective 3/2014
Retired 6/2013
Resigned 4/2013
Effective 8/2013
Effective 6/2013
Effective 2/2014
Retired 2/2014
Retired 9/2013

Number of Preferred Shareholders of
record as of December 31, 2013 was 949.

Form 10-K
A copy of the Form 10-K as filed with the
Securities and Exchange Commission will
be provided upon written request to the
office of the Corporate Secretary. For
additional information, contact the office
of the Corporate Secretary at (205) 257-
2619.

Alabama Power Company
600 North 18th Street
Birmingham, AL 35203
(205) 257-1000
www.alabamapower.com

Auditors
Deloitte & Touche LLP
420 North 20th Street
Suite 2400
Birmingham, AL 35203

Legal Counsel
Balch & Bingham LLP
P.O. Box 306
Birmingham, AL
35201

CORPORATE INFORMATION
Alabama Power Company 2013 Annual Report

General
This annual report is submitted for general
information and is not intended for use in
connection with any sale or purchase of, or
any solicitation of offers to buy or sell
securities.

Profile
The Company operates as a vertically
integrated utility providing electricity to
retail customers within its traditional
service area located within the State of
Alabama and to wholesale customers in the
Southeast. The Company sells electricity
to more than 1.4 million customers within
its service area of approximately 45,000
square miles. In 2013, retail energy sales
accounted for 83 percent of the Company’s
total sales of 66 billion kilowatt-hours.

The Company is a wholly-owned subsidiary
of The Southern Company, which is the
parent company of four traditional operating
companies and Southern Power Company.
There is no established public trading
market for the Company’s common stock.

Trustee, Registrar, and Paying Agent
All series of Senior Notes and Trust
Preferred Securities
The Bank of New York Mellon
Global Corporate Trust
505 North 20th Street, Suite 950
Birmingham, AL 35203

Registrar, Transfer Agent, and
Dividend Paying Agent
All series of Preferred and Preference Stock
Computershare Inc.
P.O. Box 43006
Providence, RI 02940-3006
(800) 554-7626

www.computershare.com/investor

[This page intentionally left blank]