A L A B A M A P O W E R C O M P A N Y
2008 Annual Report
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Alabama Power Company 2008 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 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, 2008.
This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding
internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered
public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide
only management’s report in this Annual Report.
Charles D. McCrary
President and Chief Executive Officer
Art P. Beattie
Executive Vice President, Chief Financial Officer, and Treasurer
February 25, 2009
1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 Southern Company) as of December 31, 2008 and 2007, 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,
2008. 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 25 to 61) present fairly, in all material respects, the financial position of Alabama
Power Company at December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
Birmingham, Alabama
February 25, 2009
2
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 2008 Annual Report
OVERVIEW
Business Activities
Alabama Power Company (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.
Many factors affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors
include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic
downturn, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-
term demand growth, increasingly stringent environmental standards, fuel prices, capital expenditures, and restoration following major
storms. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge the
Company for the foreseeable future.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to customers, the Company continues to focus on
several key 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 the satisfaction of its customers.
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 2008 Peak Season EFOR of 1.51% was better than the target. The
nuclear generating fleet also uses Peak Season EFOR as an indicator of availability and efficient generation fleet operations during the
peak season. The nuclear 2008 Peak Season EFOR of 2.78% did not meet 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, expected weather conditions, and expected capital expenditures. The performance for 2008 was better than the
target for these reliability measures.
Net income after dividends on preferred and preference stock is the primary component of the Company’s contribution to Southern
Company’s earnings per share goal. The Company’s 2008 results compared with its targets for some of these key indicators are
reflected in the following chart.
Key Performance Indicator
Customer Satisfaction
Peak Season EFOR – fossil/hydro
Peak Season EFOR – nuclear
Net Income
2008
Target
Performance
Top quartile in
customer surveys
2.75% or less
2.00% or less
$617 million
2008
Actual
Performance
Top quartile
1.51%
2.78%
$616 million
See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial
performance achieved in 2008 reflects the continued management emphasis, as well as the commitment shown by employees, in
achieving or exceeding these key performance expectations.
Earnings
The Company’s financial performance remained strong in 2008 despite the challenges of a weakening economy and rising costs. The
Company’s net income after dividends on preferred and preference stock of $616 million in 2008 increased $36 million (6.3%) over
the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an increase in rates under
Rate Stabilization and Equalization Plan (Rate RSE) and Rate Certificated New Plant (Rate CNP) for environmental costs that took
effect January 1, 2008, partially offset by higher non-fuel operating expenses and depreciation expense.
3
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
The Company’s 2007 net income after dividends on preferred and preference stock was $580 million, representing a $62 million
(11.9%) increase from the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an
increase in rates under Rate RSE and Rate CNP for environmental costs that took effect January 1, 2007 as well as favorable weather
conditions, partially offset by higher non-fuel operating expenses and increased interest expense.
The Company’s 2006 net income after dividends on preferred and preference stock was $518 million, representing a $10 million
(1.9%) increase from the prior year. This improvement was primarily due to retail and wholesale revenue growth offset by higher
non-fuel operating expenses and increased interest expense.
RESULTS OF OPERATIONS
A condensed income statement follows:
Operating revenues
Fuel
Purchased power
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating income
Total other income and (expense)
Income taxes
Net income
Dividends on preferred and preference stock
Net income after dividends on preferred and preference stock
Amount
2008
$6,077
2,184
538
1,259
520
307
4,808
1,269
(246)
368
655
39
$ 616
Increase (Decrease)
from Prior Year
2007
2006
2008
(in millions)
$717
422
99
73
49
20
663
54
2
16
40
4
$ 36
$345
90
12
89
21
28
240
105
(11)
21
73
11
$ 62
$367
216
(31)
53
24
9
271
96
(40)
46
10
-
$ 10
Operating Revenues
Operating revenues for 2008 were $6.1 billion, reflecting a $717 million increase from 2007. The following table summarizes the
principal factors that have affected operating revenues for the past three years:
Retail – prior year
Estimated change in –
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
2008
2007
2006
$4,407.0
(in millions)
$3,995.7
$3,621.4
246.1
26.8
(70.4)
252.8
4,862.3
711.9
308.5
1,020.4
194.2
$6,076.9
216.3
(4.9)
37.6
162.3
4,407.0
627.0
144.1
771.1
181.9
$5,360.0
48.4
35.8
19.9
270.2
3,995.7
634.6
216.0
850.6
168.4
$5,014.7
13.4%
6.9%
7.9%
Retail revenues in 2008 were $4.9 billion. These revenues increased $455 million (10.3%) in 2008, $411 million (10.3%) in 2007,
and $374 million (10.3%) in 2006. These increases were primarily due to increased fuel revenue and base rate increases of 5.6% in
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
January 2008, 5.3% in January 2007, and 2.6% in January 2006. See FUTURE EARNINGS POTENTIAL – “PSC Matters” herein
and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.
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 Fuel Cost Recovery” herein and Note 3 to the financial
statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information.
Wholesale revenues from sales to non-affiliated utilities were as follows:
Unit power sales –
Capacity
Energy
Total
Other power sales –
Capacity and other
Energy
Total
Total non-affiliated
2008
2007
(in millions)
2006
$160
238
398
134
180
314
$712
$151
192
343
$154
198
352
128
156
284
$627
137
146
283
$635
Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the
Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and
availability of Southern Company system generation.
Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to Florida utilities and sales to
wholesale customers within the Company’s service territory. Capacity revenues under unit power sales contracts reflect the recovery
of fixed costs and a return on investment, and under these contracts, energy is generally sold at variable cost. Fluctuations in oil and
natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these energy sales.
However, because energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. No significant
declines in the amount of capacity revenues are scheduled until the termination of the unit power sales contracts in May 2010. In June
2010, the units subject to the unit power sales contracts are expected to return to territorial service. As shown in the table above, unit
power sales capacity revenues have ranged from $151 million to $160 million over the last three years. 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 within the Southern Company system will vary from year to year depending on
demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in
accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC).
In 2008, wholesale revenues from sales to affiliates increased $164.4 million primarily due to a 62.2% increase in kilowatt-hour
(KWH) sales to affiliates as a result of an increase in the availability of the Company’s generating resources because of a decrease in
customer demand within the Company’s service territory. In 2007, wholesale revenues from sales to affiliates decreased $71.9 million
primarily due to a 37.0% decrease in KWH sales to affiliates as a result of a decrease in the availability of the Company’s generating
resources because of an increase in customer demand within the Company’s service territory. In 2006, wholesale revenues decreased
$73.0 million primarily due to a 16.7% decrease in price and a 10.3% decrease in KWH sales to affiliates as a result of a decrease in
the availability of the Company’s generating resources because of an increase in customer demand within the Company’s service
territory. Excluding the capacity revenues, these transactions do not have a significant impact on earnings since the energy is
generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company’s energy cost
recovery clause (Rate ECR).
Other operating revenues in 2008 increased $12.4 million (6.8%) from 2007 primarily due to an $11.7 million increase in revenues
from gas-fueled co-generation steam facilities. In 2007, other operating revenues increased $13.5 million (8.0%) from 2006 primarily
due to a $4.0 million increase in revenues from electric property associated with pole attachment and building rentals, a $2.6 million
increase in transmission revenues, and a $2.5 million increase in revenues from gas-fueled co-generation steam facilities. In 2006,
5
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
other operating revenues decreased $17.6 million (9.5%) from 2005 primarily due to a decrease of $14.6 million in revenues from gas-
fueled co-generation steam facilities mainly as a result of lower gas prices. Since co-generation steam revenues are generally offset by
fuel expense, these revenues did not have a significant impact on earnings for any year reported.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2008 and
the percent change by year were as follows:
Residential
Commercial
Industrial
Other
Total retail
Wholesale -
Non-affiliates
Affiliates
Total wholesale
Total energy sales
KWHs
2008
(in billions)
18.4
14.5
22.1
0.2
55.2
15.2
5.3
20.5
75.7
Percent Change
2007
2008
2006
(2.6)%
(1.4)
(3.2)
0.2
(2.5)
(3.6)
62.2
7.6
0.0
1.3%
2.8
(1.6)
0.7
0.5
3.1%
2.1
(0.7)
0.4
1.2
(1.3)
(37.0)
(10.0)
(2.4)
3.5
(10.3)
(0.3)
0.8
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 2008 were 2.5% less than in 2007. Energy sales were down in 2008 across all classes of
customers. Residential and commercial sales decreased 2.6% and 1.4%, respectively, due primarily to milder weather in 2008
compared to 2007. Industrial sales decreased 3.2% during the year primarily as a result of decreased customer demand in the
chemical and pipeline, and textiles and food sectors, as a result of a slowing economy that worsened during the fourth quarter of 2008.
Retail energy sales in 2007 were 0.5% higher than in 2006. Energy sales in the residential and commercial sectors led the growth with
a 1.3% and a 2.8% increase, respectively, due primarily to weather-driven increased demand. Industrial sales decreased 1.6% during
the year primarily as a result of decreased sales demand in textiles and food, primary metals, and chemical sectors.
Retail energy sales in 2006 were 1.2% higher than in 2005. Energy sales in the residential and commercial sectors led the growth with
a 3.1% and a 2.1% increase, respectively, due primarily to weather-driven increased demand. Industrial sales decreased 0.7% as
several large textile facilities discontinued or substantially reduced their operations in 2006. In addition, industrial sales decreased due
to pulp and paper customers utilizing self-generation as a result of lower gas prices during the year compared to 2005.
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. Details of the Company’s electricity generated and purchased 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)
2008
70.0
9.2
66
20
11
3
2.94
0.50
8.30
3.00
7.44
2007
69.8
9.6
69
19
10
2
2.14
0.50
7.43
2.36
6.07
2006
72.0
8.9
68
19
9
4
2.09
0.47
7.87
2.27
5.98
6
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Fuel and purchased power expenses were $2.7 billion in 2008, an increase of $521.5 million (23.7%) above the prior year costs. This
increase was the result of a $560.8 million increase in the cost of fuel, offset by a $39.3 million decrease related to the volume of
KWHs generated and purchased.
Fuel and purchased power expenses were $2.2 billion in 2007, an increase of $101.9 million (4.9%) above the prior year costs. This
increase was the result of a $70.3 million increase in the cost of fuel and a $31.6 million increase related to the volume of KWHs
generated and purchased.
Fuel and purchased power expenses were $2.1 billion in 2006, an increase of $184.1 million (9.6%) above the prior year costs. This
increase was the result of a $128.7 million increase in the cost of fuel and a $55.4 million increase related to the volume of KWHs
generated and purchased.
Purchased power consists of purchases from affiliates in the Southern Company system and non-affiliated companies. Purchased
power transactions among the Company, its affiliates, and non-affiliates will vary from period to period depending on demand and the
availability and variable production cost of generating resources at each company. Purchased power from non-affiliates increased
$81.9 million (84.5%) in 2008 due to a 67.9% increase in the amount of energy purchased. In 2007, purchased power from non-
affiliates decreased $27.1 million (21.8%) due to a 22.6% decrease in the amount of energy purchased over the previous year. In
2006, purchased power from non-affiliates decreased $64.7 million (34.3%) due to a 26.8% decrease in the amount of energy
purchased and a 10.3% decrease in purchased power prices over the previous year.
Over the last several years, coal prices have been influenced by a worldwide increase in demand from developing countries, as well as
increases in mining and fuel transportation costs. In the first half of 2008, coal prices reached unprecedented high levels primarily due
to increased demand following more moderate pricing in 2006 and 2007. Despite these fluctuations, fuel inventories have been
adequate and fuel supply markets have been sufficient to meet expected fuel requirements. Demand for natural gas in the United
States also increased in 2007 and the first half of 2008. However, natural gas supplies increased in the last half of 2008 as a result of
increased production and higher storage levels due in part to weak industrial demand. Both coal and natural gas prices moderated in
the second half of 2008 as the result of a recessionary economy. During 2008, uranium prices continued to moderate from the highs
set during 2007. While worldwide uranium production levels appear to have increased slightly since 2007, secondary supplies and
inventories were still required to meet worldwide reactor demand.
Fuel and purchased power expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s
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 Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost
Recovery” for additional information.
Other Operations and Maintenance Expenses
In 2008, other operations and maintenance expenses increased $72.7 million (6.1%) primarily due to a $27.4 million increase in steam
production expense related to environmental mandates (which were offset by revenues associated with Rate CNP environmental) and
scheduled outage costs, a $22.9 million increase in nuclear production expense related to operations and scheduled outage costs, and a
$19.9 million increase in transmission and distribution expense related to overhead line clearing costs. In 2007, other operations and
maintenance expenses increased $89.3 million (8.1%) primarily due to a $28.5 million increase in steam production expense related to
environmental mandates and scheduled outage costs, a $19.6 million increase in transmission and distribution expense related to
overhead line clearing costs, a $19.0 million increase in administrative and general expenses related to an increase in the expenses for
the injuries and damages reserve, outside services, and employee benefits, an $8.1 million increase in nuclear production expense
related to scheduled outage cost, and a $4.7 million increase in customer accounts expense associated with customer service expenses.
In 2006, other operations and maintenance expenses increased $52.8 million (5.1%) primarily due to an $18.8 million increase in
administrative and general expenses related to employee benefits, a $10.1 million increase in nuclear production expense related to
both routine operation and scheduled outage costs, a $9.8 million increase in transmission and distribution expense related to overhead
and underground line costs, and a $5.4 million increase in steam production expense related to environmental costs.
7
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Depreciation and Amortization
Depreciation and amortization expenses increased $48.9 million (10.4%) in 2008, $20.5 million (4.5%) in 2007, and $24.5 million
(5.7%) in 2006, primarily due to additions to property, plant, and equipment related to environmental mandates (which were offset by
revenues associated with Rate CNP environmental) and distribution projects. During 2008, a depreciation study was completed based
on information as of December 31, 2007. The study was filed with the FERC on October 29, 2008 and was also provided to the
Alabama PSC. The proposed rates result in an expected increase in depreciation expense for 2009 of approximately $29 million.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $19.9 million (7.0%) in 2008, $28.4 million (11.0%) in 2007, and $9.3 million (3.7%) in
2006, primarily due to increases in state and municipal public utility license taxes which are directly related to the increase in retail
revenues.
Allowance for Equity Funds Used During Construction
Allowance for equity funds used during construction (AFUDC) increased $10.1 million (28.5%) in 2008 and $17.2 million (94.1%) in
2007, primarily due to increases in the amount of construction work in progress related to environmental mandates at generating
facilities and transmission and distribution projects compared to the prior years. In 2006, AFUDC decreased $2.0 million (10.0%)
primarily due to the timing of construction expenditures compared to the prior year. See Note 1 to the financial statements under
“Allowance for Funds Used During Construction (AFUDC)” for additional information.
Income Taxes
Income taxes increased $16.6 million (4.7%) in 2008, primarily due to higher pre-tax income partially offset by the tax benefit
associated with an increase in AFUDC and a decrease in expense related to tax contingencies.
Income taxes increased $20.9 million (6.3%) in 2007, primarily due to higher pre-tax income partially offset by the tax benefit
associated with an increase in AFUDC and an increase in the Internal Revenue Code of 1986, as amended (Internal Revenue Code),
Section 199 production activities deduction.
Income taxes increased $45.6 million (16.0%) in 2006, primarily due to higher pre-tax income and the impact of a 2005 accounting
order approved by the Alabama PSC to return certain regulatory liabilities related to deferred taxes to Alabama Power’s retail
customers. See Note 5 to the financial statements for additional information.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of costs. Retail rates may be adjusted annually based on
historical or projected costs, including estimates for inflation. When historical costs are included, or when inflation exceeds the
projected costs used in rate regulation or market-based prices, the effects of inflation can create an economic loss since the recovery of
costs could be in dollars that have less purchasing power. In addition, the income tax laws are based on historical costs. Any adverse
effect of inflation on the Company’s results of operations has not been substantial. 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” herein and Note 3 to the financial statements under “FERC Matters”
and “Retail Regulatory Matters” for additional information about regulatory matters.
8
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
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 recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term
will depend, in part, upon maintaining energy sales during the current economic downturn, which is subject to a number of factors.
These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by
customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company’s service
area. Recent recessionary conditions have negatively impacted sales growth. The timing and extent of the economic recovery will
impact future earnings.
Environmental Matters
Compliance costs related to the Clean Air Act and other 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
exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand
for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as
environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental
Matters” for additional information.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern
District of Georgia against certain Southern Company subsidiaries, including the Company, alleging that it had violated the New
Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through
subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against the Company in the U.S.
District Court for the Northern District of Alabama after the Company was dismissed from the original action. In this lawsuit, the
EPA alleged that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests
penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected
units.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the
EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required
the Company to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide
emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by the
Company, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in
Alabama granted the Company’s motion for summary judgment and entered final judgment in favor of the Company on the EPA’s
claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed,
pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke
Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Company’s case
and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the
Duke Energy case. On July 24, 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment
in favor of the Company regarding the proper legal test for determining whether projects are routine maintenance, repair, and
replacement and therefore are excluded from NSR permitting. The decision did not resolve the case and the ultimate outcome of this
matter cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA regulations and interpretations 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 at each
generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital
expenditures or affect the timing of currently budgeted 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.
9
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Carbon Dioxide Litigation
New York Case
In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service
territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New
York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of
carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law
public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for
creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon
dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however,
requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and
notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the
Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs
filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, but no decision has been issued. The ultimate
outcome of these matters cannot be determined at this time.
Kivalina Case
On February 26, 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern
District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The
plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion
allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs
assert claims for public and private nuisance and contend that the defendants have acted in concert and are therefore jointly and
severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village,
which is alleged to be $95 million to $400 million. On June 30, 2008, all defendants filed motions to dismiss this case. Southern
Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims.
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 2008, the
Company had invested approximately $2.3 billion in capital projects to comply with these requirements, with annual totals of $617
million, $469 million, and $260 million for 2008, 2007, and 2006, respectively. The Company expects that capital expenditures to
assure compliance with existing and new statutes and regulations will be an additional $584 million, $131 million, and $59 million for
2009, 2010, and 2011, respectively. The Company’s compliance strategy can be affected by changes to existing environmental laws,
statutes, and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix.
Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL
CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein.
Compliance with any new federal or state legislation or regulations related to global climate change, air quality, combustion
byproducts, including coal ash, or other environmental and health concerns could also 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.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company.
Through 2008, the Company had spent approximately $2.0 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx)
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are currently being installed at several
plants to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.
In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. The Birmingham area was originally
designated as nonattainment under the eight-hour ozone standard, but has since been redesignated as an attainment area by the EPA,
and a maintenance plan to address future exceedances of the standard has been approved. On March 12, 2008, the EPA issued a final
rule establishing a more stringent eight-hour ozone standard which will likely result in designation of new nonattainment areas within
the Company’s service territory. The EPA is expected to publish those designations in 2010, and require state implementation plans
for any nonattainment areas by 2013.
During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within the
Company’s service territory, including the Birmingham area. State plans for addressing the nonattainment designations for this
standard were due by April 5, 2008 but have not been finalized. These state plans could require further reductions in SO2 and NOx
emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour
average fine particulate matter air quality standard. On December 18, 2008, the EPA designated the Birmingham area as
nonattainment for the 24-hour standard. A state implementation plan for this nonattainment area is due in 2012.
The EPA issued the final Clean Air Interstate Rule (CAIR) in March 2005. This cap-and-trade rule addresses power plant SO2 and
NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in
downwind states. Twenty-eight eastern states, including the State of Alabama, are subject to the requirements of the rule. The rule
calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. On July 11, 2008, in response to
petitions brought by certain states and regulated industries challenging particular aspects of CAIR, the U.S. Court of Appeals for the
District of Columbia Circuit issued a decision vacating CAIR in its entirety and remanding it to the EPA for further action consistent
with its opinion. On December 23, 2008, however, the U.S. Court of Appeals for the District of Columbia Circuit altered its July
decision in response to a rehearing petition and remanded CAIR to the EPA without vacatur, thereby leaving CAIR compliance
requirements in place while the EPA develops a revised rule. The State of Alabama has completed its plan to implement CAIR.
Emission reductions are being accomplished by the installation of emission controls at the Company’s coal-fired facilities and/or by
the purchase of emission allowances. The full impact of the court's remand and the outcome of the EPA's future rulemaking in
response cannot be determined at this time.
The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 2005. The goal of this rule is to restore
natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the
application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of
any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018
toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to
continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows
states to determine that the CAIR satisfies BART requirements for SO2 and NOx. Extensive studies were performed for each of the
Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. The state of
Alabama has determined that no additional SO2 controls beyond CAIR are needed to satisfy reasonable progress. States have
completed or are currently completing implementation plans that contain strategies for BART and any other measures required to
achieve the first phase of reasonable progress.
The impacts of the eight-hour ozone nonattainment designations, the fine particulate matter nonattainment designations, and the Clean
Air Visibility Rule on the Company cannot be determined at this time and will depend on the resolution of any pending legal
challenges and the development and implementation of rules at the state level.
The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance
obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the
Company plans to install additional SO2 and NOx emission controls within the next several years to ensure continued compliance with
applicable air quality requirements.
In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions
from coal-fired power plants. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of
Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury
emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam
generating units. On February 8, 2008, the court ruled in favor of the petitioners and vacated the Clean Air Mercury Rule. The
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Company’s overall environmental compliance strategy relies primarily on a combination of SO2 and NOx controls to reduce mercury
emissions. Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state
rulemakings. Future rulemakings necessitated by the court’s decision could require emission reductions more stringent than those
required by the Clean Air Mercury Rule.
Water Quality
In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing
impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures.
The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at
existing power plants. In January 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions
of the rule, including the use of cost-benefit analysis, to the EPA for revisions. The decision has been appealed to the U.S. Supreme
Court. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of
studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory
agencies and, therefore, cannot be determined at this time.
Environmental Remediation
The Company must comply with other 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. See Note 3 to the
financial statements under “Environmental Matters – Environmental Remediation” for additional information.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions and renewable energy
standards continue to be strongly considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high
priority by the current Administration. The ultimate outcome of these proposals cannot be determined at this time; however,
mandatory restrictions on the Company’s greenhouse gas emissions 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.
In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions
from new motor vehicles. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from
this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of
these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory
restrictions on the Company’s greenhouse gas emissions 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.
In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on
June 25, 2008, Florida’s Governor signed comprehensive energy-related legislation that includes authorization for the Florida
Department of Environmental Protection to adopt rules for a cap-and-trade regulatory program to address greenhouse gas emissions
from electric utilities, conditioned upon their ratification by the legislature no sooner than the 2010 legislative session. This
legislation also authorizes the Florida PSC to adopt a renewable portfolio standard for public utilities, subject to legislative ratification.
The impact of any similar state legislation on the Company will depend on the future development, adoption, legislative ratification,
implementation, and potential legal challenges to rules governing greenhouse gas emissions and mandates regarding the use of
renewable energy, and the ultimate outcome cannot be determined at this time.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current
efforts focus on a potential successor to the Kyoto Protocol for the post 2012 timeframe, with a conclusion to this round of
negotiations targeted for the end of 2009. The outcome and impact of the international negotiations cannot be determined at this time.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
The Company continues to evaluate its future energy and emission profiles and is participating in voluntary programs to reduce
greenhouse gas emissions and to help develop and advance technology to reduce emissions.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based
prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service
territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales
by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006
could be subject to refund to a cost-based rate level.
In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the
generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot
now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for
certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and
could also result in total refunds of up to $3.9 million, plus interest. The Company believes that there is no meritorious basis for an
adverse decision in this proceeding and is vigorously defending itself in this matter.
In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its
current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April
21, 2008 and Order No. 697-B on December 12, 2008. These orders largely affirmed the FERC’s prior revision and codification of
the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the
FERC an updated market power analysis on September 2, 2008 related to its continued market-based rate authority. The ultimate
outcome of this matter cannot now be determined.
On October 17, 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate
(CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its
available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after
considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales
under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a
cost-based price for wholesale sales of less than a year. On December 18, 2008, the FERC issued an order conditionally accepting the
MBR tariff subject to certain revisions to the auction proposal. On January 21, 2009, Southern Company made a compliance filing
that accepted all the conditions of the MBR tariff order. When this order becomes final, Southern Company will have 30 days to
implement the wholesale auction. On December 31, 2008, the FERC issued an order conditionally accepting the CBR tariff subject to
providing additional information concerning one aspect of the tariff. On January 30, 2009, Southern Company filed a response
addressing the FERC inquiry to the CBR tariff order. Implementation of the energy auction in accordance with the MBR tariff order
is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern
Company retail service territory. The timing of when the FERC may issue the final orders on the MBR and CBR tariffs and the
ultimate outcome of these matters cannot be determined at this time.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to two previously executed
interconnection agreements with the Company, filed complaints at the FERC requesting that the FERC modify the agreements and
that the Company refund a total of $11.0 million previously paid for interconnection facilities. No other similar complaints are
pending with the FERC.
In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification
of Tenaska’s interconnection agreements, under the provisions of the order, the Company determined that no refund was payable to
Tenaska. The Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection
agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
were denied and the Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final
outcome of this matter cannot now be determined.
Hydro Relicensing
In July 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 July and August of 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 an annual license for the Coosa developments in August 2007 and issued an annual
license for the Warrior developments in September 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 2006, the Company initiated the process of developing an application to relicense the Martin hydroelectric project located on the
Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the
FERC in 2011.
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 now be determined.
PSC Matters
Retail Rate Adjustments
In October 2005, the Alabama PSC approved a revision to Rate RSE requested by the Company. Effective January 2007 and
thereafter, 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% per year and any annual adjustment is limited to 5%.
Retail rates remain unchanged when the return on retail common equity is projected to be between 13.0% and 14.5%. If the
Company’s actual retail return on common equity 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 on common equity fall below the allowed
equity return range.
On October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for adjustments associated with
customer charges to certain existing rate structures. This package, effective in January 2009, is expected to generate additional annual
revenues of approximately $168 million. The Company agreed to a moratorium on any increase in rates in 2009 under Rate RSE. On
December 1, 2008, the Company made its submission of projected data for calendar year 2009. See Note 3 to the financial statements
under “Retail Regulatory Matters – Rate RSE” for further information.
The Company’s retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating
facilities into retail service and the recovery of retail costs associated with certificated power purchase agreements (PPAs) under Rate
CNP. In April 2006, an annual adjustment to Rate CNP, associated with PPAs, increased retail rates by approximately 0.5%, or
$19 million annually. There was no rate adjustment associated with the annual adjustment to Rate CNP, associated with PPAs, or the
true-up adjustment in April 2007 and 2008. There will be no adjustment to the current Rate CNP to recover certificated PPA costs in
April 2009. See Note 3 to the financial statements under “Retail Regulatory Matters – Rate CNP” for additional information.
Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such
mandates. The rate mechanism, based on forward-looking information 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 invested capital. Retail rates increased due to environmental costs approximately 1.2% in January 2006, 0.6% in January
2007, and 2.4% in January 2008. On October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for
adjustments associated with customer charges to certain existing rate structures. As a part of the Alabama PSC approval of the
corrective rate package, the Alabama PSC and the Company agreed to defer any environmental rate increase from 2009 to 2010. This
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
deferral will have an immaterial impact on annual cash flows, and will have no significant effect on the Company’s revenues or net
income. On December 1, 2008, the Company made its submission of projected data for calendar year 2009. See Note 3 to the
financial statements under “Retail Regulatory Matters” for further information.
Retail Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Alabama PSC. Rates are based on an estimate of future energy
costs and the current over or under recovered balance. The Company, along with the Alabama PSC, will continue to monitor the
under recovered fuel cost balance to determine whether an additional adjustment to billing rates is required.
In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per KWH effective with billings
beginning July 2007 for the 30-month period ending December 2009. The previous rate of 2.400 cents per KWH had been in effect
since January 2006. This increase was intended to permit recovery of energy costs based on an estimate of future energy cost, as well
as the collection of the existing under recovered energy cost by the end of 2009. During the recovery period, the Company was
allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the
application of this increased Rate ECR factor results in an over recovered position during this period, the Company would pay interest
on any such over recovered balance at the same rate used to derive the carrying cost.
On October 7, 2008, the Alabama PSC approved an increase in the Company’s Rate ECR factor to 3.983 cents per KWH for a 24-
month period beginning with October 9, 2008 billings. Thereafter, the Rate ECR factor is 5.910 cents per KWH, absent a contrary
order by the Alabama PSC. The previous rate of 3.100 cents per KWH had been in effect since June 2007. During the 24-month
period, the Company will be allowed to continue to include a carrying charge associated with the under recovered fuel costs in the fuel
expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this
period, the Company will pay interest on any such over recovered balance at the same rate used to derive the carrying cost.
The Company’s under recovered fuel costs as of December 31, 2008 totaled $305.8 million as compared to $279.8 million at
December 31, 2007. As a result of the Alabama PSC orders, the Company classified $180.9 million and $81.7 million of the under
recovered regulatory clause revenues as deferred charges and other assets in the balance sheets as of December 31, 2008 and
December 31, 2007, respectively. This classification is based on an estimate which includes 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
the recovery of the under recovered fuel costs.
Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable costs and amounts
billed in current regulated rates. Accordingly, this approved increase in the billing factor will have no significant effect on the
Company’s revenues or net income, but will increase annual cash flow.
Natural Disaster Cost Recovery
Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expense to cover the cost
of damages from major storms to its transmission and distribution facilities. See Note 1 and Note 3 to the financial statements under
“Natural Disaster Reserve” and “Retail Regulatory Matters - Natural Disaster Cost Recovery,” respectively, for additional information
on these reserves.
In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted natural disaster reserve (NDR) due
to hurricanes in 2005 and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to
record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also
approved a separate monthly NDR charge consisting of two components beginning in January 2006. The first component is intended
to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing.
Assuming no additional storms, the Company currently expects that the target reserve balance could be achieved within three years.
The second component of the NDR charge is intended to allow recovery of any existing deferred hurricane related operations and
maintenance costs and any future reserve deficits over a 24-month period. Absent further Alabama PSC approval, the maximum total
NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential
customer account.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
At December 31, 2008, the Company had an accumulated balance of $33.2 million in the target reserve for future storms, which is
included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its storm costs of
$51.3 million resulting from previous hurricanes. As a result, customer rates decreased by this portion of the NDR charge effective in
July 2007.
As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also
be recognized. As a result, this increase in revenue and expense will not have an impact on net income but will increase annual cash
flow.
Income Tax Matters
Legislation
On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax
incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives. These incentives could
have a significant impact on the Company’s future cash flow and net income. Additionally, the ARRA includes programs for
renewable energy, transmission and smart grid enhancement, fossil energy and research, and energy efficiency and conservation. The
ultimate impact cannot be determined at this time.
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as
defined in Section 199 (production activities deduction) of the Internal Revenue Code of 1986, as amended (Internal Revenue Code).
The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years
2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9%
rate thereafter. The Internal Revenue Service has not clearly defined a methodology for calculating this deduction. However, Southern
Company has agreed with the IRS on a calculation methodology and signed a closing agreement on December 11, 2008. Therefore, the
Company reversed the unrecognized tax benefit and adjusted the deduction to conform to the agreement. The net impact of the reversal
of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s
financial statements. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the
Company recorded non-cash pre-tax pension income of approximately $26 million, $17 million, and $13 million in 2008, 2007, and
2006, respectively. Postretirement benefit costs for the Company were $23 million, $27 million, and $28 million in 2008, 2007, and
2006, 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. In addition, the Company’s
business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout
the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials 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 liabilities, if any, arising
from such current proceedings would have a material adverse effect on the Company’s financial statements. See Note 3 to the
financial statements for information regarding material issues.
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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States.
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 critical accounting policies and estimates described below 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. These regulatory agencies
set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB
Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires 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 SFAS No. 71 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, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s
financial statements than they would on a non-regulated company.
As reflected in Note 1 to the financial statements under “Regulatory Assets and Liabilities,” significant regulatory assets and liabilities
have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable
regulatory guidelines and accounting principles generally accepted in the United States. 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 results of operations.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially
subject it to environmental, litigation, income tax, 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 generally accepted accounting principles, records reserves for those matters where a non-tax-
related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax
position will be sustained. 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. These events or
conditions include the following:
•
•
•
•
•
Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality,
control of toxic substances, hazardous and solid wastes, and other environmental matters.
Changes in existing income tax regulations or changes in IRS or Alabama Department of Revenue interpretations of existing
regulations.
Identification of sites that require environmental remediation or the filing of other complaints in which the Company may be
asserted to be a potentially responsible party.
Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, the FERC, or
the EPA.
17
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Unbilled Revenues
Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination
of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout
the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated.
Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost
in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation
patterns, power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical
trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on
the Company’s results of operations.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition remained stable at December 31, 2008. Throughout the recent turmoil in the financial markets,
the Company has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to
support its commercial paper programs and variable rate pollution control revenue bonds. The Company has continued to issue
commercial paper at reasonable rates. 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. No material changes in bank credit
arrangements have occurred, although market rates for committed credit have increased and the Company may be subject to higher
costs as its existing facilities are replaced or renewed. The Company’s interest cost for short-term debt has decreased as market short-
term interest rates have declined. The ultimate impact on future financing costs as a result of the financial turmoil cannot be
determined at this time. The Company experienced no material counterparty credit losses as a result of the turmoil in the financial
markets. See “Sources of Capital” and “Financing Activities” herein for additional information.
The Company’s investments in pension and nuclear decommissioning trust funds declined in value as of December 31, 2008. The
Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could
be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal
legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this
time. The Company does not expect any changes to the funding obligations to the nuclear decommissioning trust at this time.
Net cash provided from operating activities in 2008 totaled $1.2 billion, an increase of $30 million as compared to 2007. Significant
changes in operating cash flow for 2008 included an increase in the use of funds for fossil fuel inventory and payment of operating
expenses along with a higher receivables balance as compared 2007. This use of funds was offset by an increase in cash from net
income as previously discussed and higher depreciation expense along with a decrease in the payments for federal taxes as compared
to 2007. Net cash provided from operating activities in 2007 totaled $1.2 billion, an increase of $194 million as compared to 2006.
The increase was primarily due to an increase in net income resulting from price increases, an increase in deferred taxes and the
timing of payments related to operating expenses. Net cash provided from operating activities in 2006 totaled $956 million, an
increase of $48 million as compared to 2005. The increase was primarily due to higher recovery rates for fuel and purchased power
partially offset by the timing of payments for operating expenses.
Net cash used for investing activities totaled $1.6 billion, $1.3 billion, and $1.0 billion for 2008, 2007, and 2006, respectively,
primarily due to gross property additions to utility plant of $1.5 billion, $1.2 billion and $0.9 billion for 2008, 2007, and 2006,
respectively. These additions were primarily related to construction of transmission and distribution facilities, replacement of steam
generation equipment, purchases of nuclear fuel, and environmental mandates.
Net cash provided from financing activities totaled $375 million in 2008, $162 million in 2007, and $14 million in 2006 primarily due
to long term debt issuances and cash raised from common stock sales in excess of redemptions of securities and dividends paid.
Fluctuations in cash flow from financing activities vary from year to year based on capital needs and securities redeemed.
Significant balance sheet changes for 2008 include an increase of $966 million in gross plant and an increase of $855 million in long-
term debt, primarily due to an increase in environmental-related equipment. Other significant balance sheet changes were a result of a
decline in the market value of the Company’s pension trust and nuclear decommissioning trust funds, impacting the Company’s other
regulatory assets and liabilities. See Note 1 to the financial statements under “Regulatory Assets and Liabilities” and “Nuclear
18
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Decommissioning” and Note 2 under “Pension Plans” for additional information. In 2007, significant balance sheet changes included
an increase of $671 million in gross plant and an increase of $602 million in long-term debt, primarily due to an increase in
environmental-related equipment.
The Company’s ratio of common equity to total capitalization, including short-term debt, was 42.5% in 2008, 42.5% in 2007, and
42.1% in 2006. See Note 6 to the financial statements for additional information.
The Company has maintained investment grade credit ratings from the major rating agencies with respect to debt, preferred securities,
preferred stock, and preference stock. See SELECTED FINANCIAL AND OPERATING DATA for additional information regarding
the Company’s securities ratings.
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,
which were primarily from operating cash flows, unsecured debt, common stock, preferred stock, and preference stock. However, the
type and timing of any financings will depend on 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 Securities and Exchange Commission 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.
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.
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.
To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At December
31, 2008, the Company had approximately $28.2 million of cash and cash equivalents and $1.3 billion of unused credit arrangements
with banks, as described below. 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.
The Company maintains committed lines of credit in the amount of $1.3 billion, of which $466 million will expire at various times
during 2009. $379 million of the credit facilities expiring in 2009 allow for the execution of term loans for an additional one-year
period. $765 million of credit facilities expire in 2012. See Note 6 to the financial statements under “Bank Credit Arrangements” for
additional information.
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 and are not commingled with proceeds from such issuances for the
benefit of any other traditional operating company. The obligations of each company under these arrangements are several and there
is no cross affiliate credit support.
As of December 31, 2008, the Company had $25 million of commercial paper outstanding. As of December 31, 2007, the Company
had no commercial paper outstanding.
19
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Financing Activities
During 2008, the Company issued $850 million of senior notes and incurred obligations related to the issuance of $254 million of tax-
exempt bonds. In addition, the Company issued a total of 7.5 million shares of its common stock at $40.00 per share and realized
proceeds of $300 million. The proceeds of these issuances were used to repay short-term indebtedness, to fund certain pollution
control, environmental improvement facilities and solid waste disposal facilities, and for general corporate purposes.
Also during 2008, the Company paid at maturity $410 million of senior notes and redeemed 1,250 shares of its Flexible Money
Market Class A Preferred Stock (Series 2003A), Stated Capital $100,000 Per Share ($125 million aggregate value).
Also during 2008, the Company entered into $330 million notional amount of interest rate swaps related to variable rate pollution
control revenue bonds to hedge changes in interest rates for the period February 2008 through February 2010. The weighted average
fixed payment rate on these hedges is 2.49% and the Company now has a total of $576 million of such hedges in place, with an overall
weighted average fixed payment rate of 2.69%.
The Company converted its $246.5 million obligation related to auction rate pollution control revenue bonds from an auction rate
mode to fixed rate interest modes. With the completion of this conversion in March 2008, none of the outstanding securities or
obligations of the Company is subject to an auction rate mode.
Also during 2008, the Company was required to purchase a total of approximately $11 million of variable rate pollution control
revenue bonds that were tendered by investors, all of which were subsequently remarketed.
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 BBB- and/or Baa3 or below. These contracts are primarily for fuel purchases, fuel transportation and
storage, emission allowances, and energy price risk management. At December 31, 2008, the maximum potential collateral
requirements under these contracts at a BBB- and/or Baa3 rating were approximately $2 million. At December 31, 2008, the
maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $99 million.
Included in these amounts are certain agreements that could require collateral in the event that one or more 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.
Market Price Risk
Due to cost-based rate regulations, the Company has 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. Company 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.
20
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
To mitigate future exposure to changes in interest rates, the Company enters into forward starting interest rate swaps and other
derivatives that have been designated as hedges. The weighted average interest rate on $250 million of long-term variable interest rate
exposure that has not been hedged at January 1, 2009 was 2.34%. 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 $2.5 million at
January 1, 2009. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase
and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas
purchases. The Company has implemented fuel hedging programs per the guidelines of the Alabama PSC.
In addition, the Company’s 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.
The changes in fair value of energy-related derivative contracts were as follows at December 31:
2008
Changes
2007
Changes
Fair Value
(in millions)
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
$ (0.4)
(44.0)
(47.5)
$(91.9)
$(32.6)
31.5
0.7
$ (0.4)
(a)
Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The decrease in the fair value positions of the energy-related derivative contracts for the year-ended December 31, 2008 was $91.5
million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural
gas. At December 31, 2008, the Company had a net hedge volume of 44.5 billion cubic feet (Bcf) with a weighted average contract
cost approximately $2.12 per million British thermal units (mmBtu) above market prices, and 27.4 Bcf at December 31, 2007 with a
weighted average contract cost approximately $0.02 per mmBtu above market prices. The majority of the natural gas hedges are
recovered through the fuel cost recovery clauses.
At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial
statements as assets/(liabilities) as follows:
Regulatory hedges
Cash flow hedges
Non-accounting hedges
Total fair value
2008
(in millions)
$(91.9)
-
-
$(91.9)
2007
$(0.7)
0.5
(0.2)
$(0.4)
Energy-related derivative contracts which are designated as regulatory hedges relate to the Company’s fuel hedging program where
gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are
recovered through the fuel cost recovery clauses. 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.
Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year
presented.
21
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31,
2008 are as follows:
December 31, 2008
Fair Value Measurements
Total
Fair Value
Maturity
Year 1 Years 2&3 Years 4&5
Level 1
Level 2
Level 3
Fair value of contracts outstanding at end of period
$
-
(91.9)
-
$
(in millions)
-
$
(71.4)
-
-
(20.5)
-
$(91.9)
$(71.4)
$(20.5)
$ -
-
-
$ -
As part of the adoption of FASB Statement No. 157, “Fair Value Measurements” to increase consistency and comparability in fair
value measurements and related disclosures, the table above now uses the three-tier fair value hierarchy, as discussed in Note 10 to the
financial statements, as opposed to the previously used descriptions “actively quoted,” “external sources,” and “models and other
methods.” The three-tier fair value hierarchy focuses on the fair value of the contract itself, whereas the previous descriptions focused
on the source of the inputs. Because the Company uses over-the-counter contracts that are not exchange traded but are fair valued
using prices which are actively quoted, the valuations of those contracts now appear in Level 2; previously they were shown as
“actively quoted.”
The Company is exposed to market risk in the event of nonperformance by counterparties to energy-related and interest rate derivative
contracts. The Company’s practice is to enter into agreements with counterparties that have investment grade credit ratings by
Moody’s and Standard & Poor’s 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
Notes 1 and 6 to the financial statements under “Financial Instruments.”
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $1.4 billion for 2009, $1.0 billion for 2010, and $1.0 billion for
2011. Environmental expenditures included in these estimated amounts are $584 million, $131 million, and $59 million for 2009,
2010, and 2011, respectively. Also included over the next three years, the Company estimates spending $586 million on Plant Farley
(including $341 million for nuclear fuel), $950 million on distribution facilities, and $387 million on transmission additions. See
Note 7 to the financial statements under “Construction Program” for additional details.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates
because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in
environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and
regulations; Alabama PSC approvals; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital.
In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. As a result of Nuclear
Regulatory Commission 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.”
In addition to the funds required for the Company’s construction program, approximately $550 million will be required by the end of
2011 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.
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 a long period will diminish internally funded capital for other purposes and may require the
Company to seek capital from other sources. For additional information, see Note 2 to the financial statements under “Postretirement
Benefits.”
Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as
well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments,
are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.
22
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2008 Annual Report
Contractual Obligations
Long-term debt(a) –
Principal
Interest
Preferred and preference stock dividends(b)
Energy-related derivative obligations(c)
Operating leases
Purchase commitments(d) –
Capital (e)
Limestone(f)
Coal
Nuclear fuel
Natural gas (g)
Purchased power
Long-term service agreements(h)
Postretirement benefits trust(i)
Total
2009
$ 250
291
39
75
23
1,365
3
1,461
48
505
105
18
17
$4,200
2010-
2011
$ 300
549
79
20
28
1,865
24
1,804
82
386
44
35
35
$5,251
2012-
2013
(in millions)
$ 750
499
79
-
12
After
2013
Total
$ 4,558
4,351
-
-
11
$ 5,858
5,690
197
95
74
-
29
1,110
76
311
-
29
-
$2,895
-
68
1,414
10
210
-
37
-
3,230
124
5,789
216
1,412
149
119
52
$10,659 $23,005
(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, 2009, 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.
(c) For additional information, see Notes 1 and 6 to the financial statements.
(d) The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and
maintenance expenses for 2008, 2007, and 2006 were $1.26 billion, $1.19 billion, and $1.10 billion, respectively.
(e) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts
related to contractual purchase commitments for nuclear fuel. At December 31, 2008, significant purchase commitments were outstanding in connection with
the construction program.
(f) As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company has begun construction of flue gas
desulfurization projects and has entered into various long-term commitments for the procurement of limestone to be used in such equipment.
(g) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York
Mercantile Exchange future prices at December 31, 2008.
(h) Long-term service agreements include price escalation based on inflation indices.
(i) The Company forecasts postretirement trust contributions over a three-year period. The Company expects that the earliest that cash may have to be
contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on
interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and
cannot be determined at this time. Therefore, no amounts related to the pension trust are included in the table. See Note 2 to the financial statements for
additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through
the related trusts. Other benefit payments will be made from the Company’s corporate assets.
23
MANAGEMENT’S DISCUSSION AND ANALYSIS (Continued)
Alabama Power Company 2008 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2008 Annual Report contains forward-looking statements. Forward-looking statements include, among other things,
statements concerning retail sales growth and retail rates, storm damage cost recovery and repairs, fuel cost recovery and other rate
actions, environmental regulations and expenditures, access to sources of capital, projections for postretirement benefit and nuclear
decommissioning trust contributions, financing activities, completion of construction projects, filings with state and federal regulatory
authorities, impacts of adoption of new accounting rules, 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 change, including legislative and regulatory initiatives regarding
deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005,
environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or
particulate matter 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 and the pending
EPA civil action against the Company;
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, population and business
growth (and declines), and the effects of energy conservation measures;
available sources and costs of fuels;
effects of inflation;
ability to control costs;
investment performance of the Company’s employee benefit plans;
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 storm restoration cost recovery;
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 neighboring utilities;
the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit
ratings;
the ability of the Company to obtain additional generating capacity at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an
avian influenza, or other similar occurrences;
the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in
the Northeast;
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.
24
STATEMENTS OF INCOME
For the Years Ended December 31, 2008, 2007, and 2006
Alabama Power Company 2008 Annual Report
Operating Revenues:
Retail revenues
Wholesale revenues --
Non-affiliates
Affiliates
Other revenues
Total operating revenues
Operating Expenses:
Fuel
Purchased power --
Non-affiliates
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
Net Income After Dividends on Preferred and Preference Stock
The accompanying notes are an integral part of these financial statements.
2008
2007
(in thousands)
2006
$4,862,281
$4,406,956
$3,995,731
711,903
308,482
194,265
6,076,931
627,047
144,089
181,901
5,359,993
634,552
216,028
168,417
5,014,728
2,184,310
1,762,418
1,672,831
178,807
359,202
1,258,888
520,449
306,522
4,808,178
1,268,753
45,519
19,394
(278,917)
(31,514)
(245,518)
1,023,235
367,813
655,422
39,463
$ 615,959
96,928
341,461
1,186,235
471,536
286,579
4,145,157
1,214,836
35,425
19,545
(273,737)
(29,144)
(247,911)
966,925
351,198
615,727
36,145
$ 579,582
124,022
302,045
1,096,978
451,018
258,135
3,905,029
1,109,699
18,253
20,897
(252,282)
(23,758)
(236,890)
872,809
330,345
542,464
24,734
$ 517,730
25
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2008, 2007, and 2006
Alabama Power Company 2008 Annual Report
Operating Activities:
Net income
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization
Deferred income taxes and investment tax credits, net
Allowance for equity funds used during construction
Pension, postretirement, and other employee benefits
Stock based compensation expense
Tax benefit of stock options
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
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
Other
Net cash used for investing activities
Financing Activities:
Increase (decrease) in notes payable, net
Proceeds --
Senior notes
Preferred and preference stock
Common stock issued to parent
Capital contributions
Gross excess tax benefit of stock options
Pollution control revenue bonds
Redemptions --
Senior notes
Preferred stock
Pollution control revenue bonds
Other long-term debt
Payment of preferred and preference stock dividends
Payment of common stock dividends
Other
Net cash provided from 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 --
2008
2007
(in thousands)
2006
$ 655,422
$ 615,727
$ 542,464
599,767
126,538
(45,519)
(26,530)
3,105
685
27,689
(31,693)
(134,212)
(17,723)
(1,494)
(8,751)
36,957
(4,722)
(198)
1,179,321
(1,477,643)
(96,326)
35,979
(300,503)
299,636
(41,744)
(19,143)
(1,599,744)
548,959
21,269
(35,425)
(18,781)
4,900
1,118
(13,650)
(5,797)
(33,840)
(32,543)
22,354
78,508
(17,248)
4,194
10,098
1,149,843
(1,157,186)
(97,775)
78,043
(334,275)
333,409
(48,932)
(26,621)
(1,253,337)
524,313
(27,562)
(18,253)
(15,196)
4,848
610
29,564
(33,260)
(28,179)
(25,711)
38,645
(49,725)
1,124
(6,157)
18,486
956,011
(933,306)
-
-
(286,551)
285,685
(40,834)
(1,777)
(976,783)
24,995
(119,670)
(195,609)
850,000
-
300,000
21,272
1,289
265,100
(410,000)
(125,000)
(11,100)
-
(40,899)
(491,300)
(9,369)
374,988
(45,435)
73,616
28,181
$
850,000
200,000
229,000
27,867
2,556
265,500
(668,500)
-
-
(103,093)
(31,380)
(465,000)
(25,709)
161,571
58,077
15,539
73,616
$
950,000
150,000
120,000
27,160
1,291
-
(546,500)
-
(2,950)
-
(24,318)
(440,600)
(24,635)
13,839
(6,933)
22,472
15,539
$
Interest (net of $20,215, $17,961, and $7,930 capitalized, respectively)
Income taxes (net of refunds)
$258,918
214,368
$248,289
340,951
$245,387
345,803
The accompanying notes are an integral part of these financial statements.
26
BALANCE SHEETS
At December 31, 2008 and 2007
Alabama Power Company 2008 Annual Report
Assets
Current Assets:
Cash and cash equivalents
Restricted cash
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
Total current assets
Property, Plant, and Equipment:
In service
Less accumulated provision for 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
Other
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
Other
Total deferred charges and other assets
Total Assets
The accompanying notes are an integral part of these financial statements.
27
2008
(in thousands)
2007
$
28,181
80,079
$
73,616
19,732
350,409
98,921
153,899
44,645
70,612
(8,882)
322,089
305,880
52,577
88,220
87,740
1,674,370
17,635,129
6,259,720
11,375,409
231,862
1,092,516
12,699,787
50,912
403,966
62,782
517,660
362,596
166,334
180,874
732,367
202,018
1,644,189
$16,536,006
357,355
95,278
232,226
42,745
61,250
(7,988)
182,963
287,994
50,266
72,952
19,610
1,487,999
16,669,142
5,950,373
10,718,769
137,146
928,182
11,784,097
48,664
542,846
31,146
622,656
347,193
989,085
81,650
224,792
209,153
1,851,873
$15,746,625
2008
(in thousands)
2007
$ 250,079
24,995
$
535,152
-
178,708
358,176
77,205
18,299
30,372
56,375
44,217
91,856
83,873
53,777
1,267,932
5,604,791
2,243,117
90,083
172,638
396,923
461,284
634,792
79,150
45,859
4,123,846
10,996,569
685,127
4,854,310
$16,536,006
193,518
308,177
67,722
45,958
29,198
55,263
42,138
92,385
6,404
48,927
1,424,842
4,750,196
2,065,264
93,709
180,578
349,974
505,794
613,616
637,040
31,417
4,477,392
10,652,430
683,512
4,410,683
$15,746,625
BALANCE SHEETS
At December 31, 2008 and 2007
Alabama Power Company 2008 Annual Report
Liabilities and Stockholder's Equity
Current Liabilities:
Securities due within one year
Notes payable
Accounts payable --
Affiliated
Other
Customer deposits
Accrued taxes --
Income taxes
Other
Accrued interest
Accrued vacation pay
Accrued compensation
Liabilities from risk management activities
Other
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
Other
Total deferred credits and other liabilities
Total Liabilities
Preferred and 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.
28
STATEMENTS OF CAPITALIZATION
At December 31, 2008 and 2007
Alabama Power Company 2008 Annual Report
Long-Term Debt:
Long-term debt payable to affiliated trusts --
5.5% due 2042
Long-term notes payable --
3.125% to 5.375% due 2008
Floating rate (2.34% at 1/1/09) due 2009
4.70% due 2010
5.10% due 2011
4.85% due 2012
5.80% due 2013
5.125% to 6.375% due 2016-2047
Total long-term notes payable
Other long-term debt --
Pollution control revenue bonds:
2.00% to 5.00% due 2030-2038
Variable rates (0.92% to 1.83% at 1/1/09)
due 2015-2036
Total other long-term debt
Capitalized lease obligations
Unamortized debt premium (discount), net
Total long-term debt (annual interest
requirement -- $290.8 million)
Less amount due within one year
Long-term debt excluding amount due within one year
2008
2007
(in thousands)
2008
(percent of total)
2007
$ 206,186
$ 206,186
-
250,000
100,000
200,000
500,000
250,000
3,275,000
4,575,000
500,500
576,190
1,076,690
79
(3,085)
5,854,870
250,079
5,604,791
410,000
250,000
100,000
200,000
200,000
-
2,975,000
4,135,000
-
822,690
822,690
231
(3,759)
5,160,348
410,152
4,750,196
50.3%
48.3%
29
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2008 and 2007
Alabama Power Company 2008 Annual Report
Preferred and Preference Stock:
Cumulative 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
Outstanding - 2008: 0 shares
2007: 1,250 shares: $100,000 stated capital
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
Total preferred and preference stock
(annual dividend requirement -- $39.5 million)
Less amount due within one year
Preferred and preference stock
excluding amount due within one year
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 2008: 40,000,000 shares
- 2007: 25,000,000 shares
Outstanding - 2008: 25,475,000 shares
- 2007: 17,975,000 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.
2008
2007
(in thousands)
2008
(percent of total)
2007
47,610
47,610
294,105
-
294,105
123,331
343,412
343,466
685,127
-
808,512
125,000
685,127
683,512
6.1
6.9
1,019,000
719,000
2,091,462
1,753,797
(9,949)
4,854,310
$11,144,228
2,065,298
1,630,832
(4,447)
4,410,683
$9,844,391
43.6
100.0% 100.0%
44.8
30
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2008, 2007, and 2006
Alabama Power Company 2008 Annual Report
Common
Stock
Paid-In
Capital
Retained
Earnings
Accumulated
Other Comprehensive
Income (Loss)
(in thousands)
$370,000
-
120,000
-
-
-
-
-
490,000
229,000
-
-
-
-
719,000
Balance at December 31, 2005
Net income after dividends on preferred stock
Issuance of common stock
Capital contributions from parent company
Other comprehensive income (loss)
Adjustment to initially apply
FASB Statement No. 158, net of tax
Cash dividends on common stock
Other
Balance at December 31, 2006
Net income after dividends on preferred
and preference stock
Issuance of common stock
Capital contributions from parent company
Other comprehensive income (loss)
Cash dividends on common stock
Other
Balance at December 31, 2007
Net income after dividends on preferred
and preference stock
Issuance of common stock
Capital contributions from parent company
Other comprehensive income (loss)
Cash dividends on common stock
Other
Balance at December 31, 2008
The accompanying notes are an integral part of these financial statements.
-
300,000
-
-
-
-
$1,019,000
-
-
579,582
$1,995,056
-
-
33,907
-
-
-
-
2,028,963
$1,439,144
517,730
-
-
-
-
(440,600)
(29)
1,516,245
-
36,441
-
-
(106)
2,065,298
-
-
26,164
-
-
-
$2,091,462
-
-
-
(465,000)
5
1,630,832
615,959
-
-
-
(491,300)
(1,694)
$1,753,797
$(11,474)
-
-
-
(4,057)
12,610
-
-
(2,921)
-
-
-
(1,526)
-
-
(4,447)
-
-
-
(5,502)
-
-
$( 9,949)
Total
$3,792,726
517,730
120,000
33,907
(4,057)
12,610
(440,600)
(29)
4,032,287
579,582
229,000
36,441
(1,526)
(465,000)
(101)
4,410,683
615,959
300,000
26,164
(5,502)
(491,300)
(1,694)
$4,854,310
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2008, 2007, and 2006
Alabama Power Company 2008 Annual Report
Net income after dividends on preferred and preference stock
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(4,297), $(1,226),
and $155, respectively
Reclassification adjustment for amounts included in net income,
net of tax of $952, $298, and $(3,696), respectively
Pension and other postretirement benefit plans:
Change in additional minimum pension liability,
net of tax of $-, $-, and $1,109, respectively
Total other comprehensive income (loss)
Comprehensive Income
The accompanying notes are an integral part of these financial statements.
31
2008
2007
(in thousands)
2006
$615,959
$579,582
$517,730
(7,068)
(2,017)
1,566
491
-
(5,502)
$610,457
-
(1,526)
$578,056
255
(6,080)
1,768
(4,057)
$513,673
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2008 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of 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). The Company provides electricity to retail customers within its traditional service area located within the State of
Alabama and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, 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 for Southern Company’s investments in leveraged
leases and various other energy-related businesses. The investments in synthetic fuels ended on December 31, 2007. Southern Nuclear
operates and provides services to Southern Company’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 where the Company 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 accounting principles generally accepted in the United States and complies with the
accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from
those estimates.
Reclassifications
Certain prior years’ data presented in the financial statements have been reclassified to conform with current year presentation. The
statements of cash flows for the prior periods presented have been modified within the operating activities section to combine the
amount of “Deferred revenues” and “Hedge settlements” into “Other, net.” The statements of income for the prior periods presented
have been modified within the operating expenses section to combine the line items “Other operations” and “Maintenance” into a
single line item entitled “Other operations and maintenance.” The balance sheet at December 31, 2007 was modified to present a
separate line for “Liabilities for risk management activities” previously included in “Other.” These reclassifications had no effect on
total assets, cash flows, or net income.
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, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless
communications, and other services with respect to business and operations and power pool transactions. Costs for these services
amounted to $321 million, $299 million, and $266 million during 2008, 2007, and 2006, respectively. Cost allocation methodologies
used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company
Act of 1935, as amended, 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 Southern Nuclear operates the Company’s Plant Farley and
provides the following nuclear-related services at cost: general executive and advisory services, general operations, management and
32
NOTES (continued)
Alabama Power Company 2008 Annual Report
technical services, administrative services including procurement, accounting, statistical analysis, employee relations, and other
services with respect to business and operations. Costs for these services amounted to $196 million, $182 million, and $162 million
during 2008, 2007, and 2006, 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 $11.1 million in 2008, $9.8 million in 2007, and $8.6 million in 2006. See Note 4 for additional
information.
Southern Company’s 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produced synthetic fuel was terminated in
July 2006. The Company had an agreement with an indirect subsidiary of Southern Company that provided services for AFP. Under
this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and
the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $1.2 million,
$58.1 million, and $56.5 million in 2008, 2007, and 2006, respectively. In addition, the Company purchased synthetic fuel from AFP
for use at several of the Company’s plants. Synthetic fuel purchases totaled $6.2 million, $462.1 million, and $446.6 million in 2008,
2007, and 2006, respectively. The synthetic fuel purchases and related party transactions were terminated as of December 31, 2007.
The Company had an agreement with Southern Power under which the Company operated and maintained Plant Harris at cost. On
August 1, 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern
Power specifically requested services. In 2008, 2007, and 2006, the Company billed Southern Power $0.9 million, $2.4 million, and
$2.2 million, respectively, under these agreements. Under a power purchase agreement (PPA) with Southern Power, the Company’s
purchased power costs from Plant Harris in 2008, 2007, and 2006 totaled $63.2 million, $66.3 million, and $61.7 million, respectively.
The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company was
$119.6 million in 2008, $108.1 million in 2007, and $77.8 million in 2006. Additionally, the Company recorded $8.3 million of
prepaid capacity expenses included in other deferred charges and other assets in the balance sheets at December 31, 2008, 2007 and
2006. See Note 3 under “Retail Regulatory Matters” and Note 7 under “Purchased Power Commitments” for additional information.
Also, see Note 4 for information regarding the Company’s ownership in and PPA with Southern Electric Generating Company
(SEGCO).
In the second quarter, Southern Power sold a turbine rotor assembly to the Company for approximately $8.2 million. In October 2008,
the Company also sold a rotor to Southern Power for approximately $6.3 million and sold a distance piece component to Gulf Power
for approximately $0.3 million. In the fourth quarter, the Company purchased from SEGCO two 230kV transmission lines. The
purchase price for the transmission line facilities was approximately $3.9 million. These affiliate transactions were made in
accordance with FERC and Alabama PSC rules and guidelines.
The traditional operating companies, including the Company, and Southern Power 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 Commitments” for additional
information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the
Effects of Certain Types of Regulation” (SFAS No. 71). 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.
33
NOTES (continued)
Alabama Power Company 2008 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
2008
2007 Note
(in millions)
Deferred income tax charges
Loss on reacquired debt
Vacation pay
Under recovered regulatory clause revenues
Fuel-hedging (realized and unrealized) losses
Other assets
Asset retirement obligations
Other cost of removal obligations
Deferred income tax credits
Fuel-hedging (realized and unrealized) gains
Mine reclamation and remediation
Nuclear outage
Deferred purchased power
Natural disaster reserve (future storms)
Other liabilities
Overfunded retiree benefit plans
Underfunded retiree benefit plans
Total assets (liabilities), net
$ 363
80
53
335
95
7
18
(635)
(90)
(4)
(14)
(8)
(20)
(33)
(4)
-
614
$757
$ 347
87
50
314
6
6
(150)
(614)
(94)
(5)
(14)
2
(20)
(26)
(3)
(423)
138
$ (399)
(a)
(b)
(c)
(d)
(e)
(d)
(a)
(a)
(a)
(e)
(d)
(d)
(d)
(d)
(d)
(f)
(f)
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over
the related property lives, which may range up to 50 years. Asset retirement and removal 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.
(e) Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally does not exceed two
years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses.
(f) Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
In the event that a portion of the Company’s operations is no longer subject to the provisions of SFAS No. 71, the Company would be
required to write off or reclassify to accumulated other comprehensive income 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.
Revenues
Energy and other revenues are recognized as services are provided. Wholesale capacity revenues are generally recognized on a
levelized basis over the appropriate contract periods. Unbilled revenues 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 – Fuel Cost Recovery” for additional information.
The Company has a diversified base of customers. No single customer comprises 10% or more of revenues. For all periods
presented, uncollectible accounts averaged less than one percent of revenues.
34
NOTES (continued)
Alabama Power Company 2008 Annual Report
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission 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 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 FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), 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 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/or cost of funds used during construction.
The Company’s property, plant, and equipment consisted of the following at December 31:
Generation
Transmission
Distribution
General
Plant acquisition adjustment
Total plant in service
(in millions)
2008
$ 9,096
2,559
4,827
1,141
12
$17,635
2007
$ 8,541
2,435
4,586
1,095
12
$16,669
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 maintenance expense as incurred or performed with the exception of nuclear
refueling costs, which are recorded in accordance with specific Alabama PSC orders. The Company accrues estimated nuclear
refueling costs in advance of the unit’s next refueling outage. The refueling cycle is 18 months for each unit. During 2008, the
Company accrued $39.4 million and paid $28.5 million for an outage at Plant Farley Unit 2. At December 31, 2008, the reserve
balance totaled $8.7 million and is included in the balance sheet in other regulatory liabilities.
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 2008 and 3.1% in 2007 and 2006. Depreciation studies are conducted periodically to update the composite
rates and the information is provided to the Alabama PSC and approved by the FERC. When property subject to 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 is 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.
35
NOTES (continued)
Alabama Power Company 2008 Annual Report
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 will continue to be reflected in the balance sheets as a regulatory liability.
The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facility, Plant Farley. The fair value of
assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2008 was $404 million. In
addition, the Company has retirement obligations related to various landfill sites and 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 range of time over which the Company may settle these obligations is unknown and
cannot be reasonably estimated. 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 under Statement of Financial Accounting
Standards No. 143, “Accounting for Asset Retirement Obligations” and FASB Interpretation No. 47, “Accounting for Conditional
Asset Retirement 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” for further information on amounts included
in rates.
Details of the asset retirement obligations included in the balance sheets are as follows:
2008
2007
(in millions)
Balance beginning of year
Liabilities incurred
Liabilities settled
Accretion
Cash flow revisions (a)
Balance end of year
(a) Updated based on results from 2008 Nuclear Decommissioning Study
$506
-
(2)
31
(74)
$461
$476
-
(3)
33
-
$506
Nuclear Decommissioning
The 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 an external trust fund (the Fund) to comply with the
NRC’s regulations. Use of the Fund is restricted to nuclear decommissioning activities and the Fund is 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 Fund is invested in a tax-efficient manner in a diversified mix of equity and fixed income
securities and are reported as of December 31, 2008 as trading securities pursuant to FASB Statement No. 115, “Accounting for
Certain Investments in Debt and Equity Securities” (SFAS No. 115).
On January 1, 2008, the Company adopted FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial
Liabilities – Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to
measure many financial instruments and certain other items at fair value. The Company elected the fair value option only for
investment securities held in the Fund. The Fund is included in the balance sheets at fair value, as disclosed in Note 10.
Management elected to continue to record the Fund at fair value because management believes that fair value best represents the
nature of the Fund. Management has delegated day-to-day management of the investments in the Fund to unrelated third party
managers with oversight by Company management. The managers of the Fund are authorized, within broad limits, to actively buy
and sell securities at their own discretion in order to maximize the investment return on the Fund investments. Because of the
Company’s inability to choose to hold securities that have experienced unrealized losses until recovery of their value, all unrealized
losses incurred during 2006 and 2007, prior to the adoption of SFAS No. 159, were considered other-than-temporary impairments
under SFAS No. 115.
36
NOTES (continued)
Alabama Power Company 2008 Annual Report
The adoption of SFAS No. 159 had no impact on the results of operations, cash flows, or financial condition of the Company. For all
periods presented, all gains and losses, whether realized, unrealized, or identified as other-than-temporary, have been and will
continue to be recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net
income or other comprehensive income. Fair value adjustments, realized gains, and other-than-temporary impairment losses are
determined on a specific identification basis.
At December 31, 2008, investment securities in the Fund totaled $402.9 million consisting of equity securities of $256.7 million, debt
securities of $135.3 million, and $10.9 million of other securities. These amounts exclude receivables related to investment income
and pending investment sales, and payables related to pending investment purchases.
At December 31, 2007, investment securities in the Fund totaled $542.8 million consisting of equity securities of $385.4 million, debt
securities of $140.2 million, and $17.2 million of other securities. Unrealized gains were $130.8 million for equity securities, $7.0
million debt securities, and $0.1 million for other securities. Other-than-temporary impairments were $(15.7) million for equity
securities and $(3.5) million for debt securities.
Sales of the securities held in the Fund resulted in cash proceeds of $299.6 million, $333.4 million, and $285.7 million, in 2008, 2007,
and 2006, respectively, all of which were re-invested. For 2008, fair value reductions, including reinvested interest and dividends,
were $134.4 million, of which $107.6 million related to securities held in the Fund at December 31, 2008. Realized gains and other-
than-temporary impairment losses were $34.6 million and $37.2 million, respectively, in 2007 and $22.0 million and $18.2 million,
respectively, in 2006. While the investment securities held in the Fund are reported as trading securities from the perspective of SFAS
No. 115, the Fund continues to be managed with a long-term focus. Accordingly, all purchases and sales within the Fund 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 external trust 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 external trust funds will provide the minimum funding amounts prescribed
by the NRC. At December 31, 2008, the accumulated provisions for decommissioning were as follows:
External trust funds
Internal reserves
Total
(in millions)
$404
26
$430
Site study cost is the estimate to decommission the facility as of the site study year. The estimated costs of decommissioning based on
the most current study performed in 2008 for Plant Farley was as follows:
Decommissioning periods:
Beginning year
Completion year
Site study costs:
Radiated structures
Non-radiated structures
Total
2037
2065
(in millions)
$1,060
72
$1,132
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%.
37
NOTES (continued)
Alabama Power Company 2008 Annual Report
Amounts previously contributed to the external trust fund 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. The Company continues to transfer internal reserves (less than
$1 million annually) previously collected from customers prior to the establishment of the external trust.
Allowance for Funds Used During Construction (AFUDC)
In accordance with regulatory treatment, the Company records 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, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation
expense. 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 9.2% in 2008, 9.4% in 2007, and 8.8% in 2006.
AFUDC, net of income tax, as a percent of net income after dividends on preferred and preference stock was 9.4% in 2008, 8.0% in
2007, and 4.5% in 2006.
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
In accordance with an Alabama PSC order, the Company has established a natural disaster reserve (NDR) to cover the cost of
uninsured damages from major storms to transmission and distribution facilities. The Company is authorized to collect a monthly
NDR charge per account that consists of two components which began on January 1, 2006. The first component is intended to
establish and maintain a reserve for future storms and is an on-going part of customer billing. This plan has a target reserve balance of
$75 million that could be achieved within three years assuming the Company experiences no additional storms. The second
component of the NDR charge is intended to allow recovery of any existing deferred hurricane related operations and maintenance
costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to have a negative
NDR balance when costs of uninsured storm damage exceed any established NDR balance. Absent further Alabama PSC approval,
the maximum total NDR charge consisting of both components is $10 per month per account for non-residential customers and $5 per
month per account for residential customers.
At December 31, 2008, the Company had accumulated a balance of $33.2 million in the target reserve for future storms, which is
included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its prior storm cost of
$51.3 million resulting from Hurricanes Dennis and Katrina. As a result, customer rates decreased by this portion of the NDR charge
effective July 1, 2007.
As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expense related to the NDR will also
be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase annual cash
flow.
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.
38
NOTES (continued)
Alabama Power Company 2008 Annual Report
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 expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when
purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Alabama PSC.
Emission allowances granted by the 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
(categorized 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 exempt from fair value accounting requirements 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 other comprehensive income or regulatory assets and liabilities,
respectively, until the hedged transactions occur. Any 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 6 under “Financial Instruments” 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 has no outstanding collateral repayment obligations or rights to
reclaim collateral arising from derivative instruments recognized at December 31, 2008.
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.
The Company’s other financial instruments for which the carrying amounts did not equal fair values at December 31 were as follows:
Long-term debt:
2008
2007
Carrying Amount
Fair Value
(in millions)
$5,855
5,160
$5,784
5,079
The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). See Note
10 for all other items recognized at fair value in the financial statements.
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 prior to the adoption of SFAS No.158, “Employers’ Accounting
for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), the minimum pension liability, less income taxes and
reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established
certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for
additional information. However, the Company is not considered the primary beneficiary of the trusts. Therefore, the investments in
39
NOTES (continued)
Alabama Power Company 2008 Annual Report
these trusts are reflected as Other Investments, and the related loans from the trusts are included in Long-term Debt in the balance
sheets.
Investments
The Company maintains an investment in a debt security that matures in 2018 and is classified as available-for-sale. This security is
included in the balance sheets under Other Property and Investments-Other and totaled $0.4 million and $2.3 million at December 31,
2008 and 2007, respectively. Because the interest rate resets weekly, the carrying value approximates the fair market value.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance
with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are
expected for the year ending December 31, 2009. 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 trusts to the extent required by the Alabama PSC and the FERC. For the year
ending December 31, 2009, postretirement trust contributions are expected to total approximately $17.2 million.
The measurement date for plan assets and obligations for 2008 was December 31 while the measurement date for prior years was
September 30. Pursuant to SFAS No. 158, the Company was required to change the measurement date for its defined benefit
postretirement plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, the
Company adopted the measurement date provisions of SFAS No. 158 effective January 1, 2008 resulting in an increase in long-term
liabilities of approximately $5 million and an increase in prepaid pension costs of approximately $11 million.
Pension Plans
The total accumulated benefit obligation for the pension plans was $1.4 billion in 2008 and $1.3 billion in 2007. Changes during the
15-month period ended December 31, 2008 and 12-month period ended September 30, 2007 in the projected benefit obligations and
the fair value of plan assets were as follows:
2008
2007
(in millions)
Change in benefit obligation
Benefit obligation at beginning of year
Service cost
Interest cost
Benefits paid
Plan amendments
Actuarial (gain) loss
Balance at end of year
Change in plan assets
Fair value of plan assets at beginning of year
Actual return (loss) on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at end of year
Funded status at end of year
Fourth quarter contributions
Prepaid pension asset, net
$1,420
43
109
(94)
-
(18)
1,460
2,318
(692)
7
(94)
1,539
79
-
$ 79
$1,394
35
82
(70)
10
(31)
1,420
2,038
346
4
(70)
2,318
898
2
$ 900
40
NOTES (continued)
Alabama Power Company 2008 Annual Report
At December 31, 2008, the projected benefit obligations for the qualified and non-qualified pension plans were $1.4 billion and $87
million, respectively. All pension plan assets are related to the qualified pension plan.
Pension 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 policy covers a diversified mix of assets,
including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools
but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses
through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan
assets as of the end of year, along with the targeted mix of assets, is presented below:
Domestic equity
International equity
Fixed income
Real estate
Private equity
Total
Target
36%
24
15
15
10
100%
2008
34%
23
14
19
10
100%
2007
38%
24
15
16
7
100%
Amounts recognized in the balance sheets related to the Company’s pension plans consist of:
Prepaid pension asset
Other regulatory assets
Current liabilities, other
Other regulatory liabilities
Employee benefit obligations
2008
(in millions)
$166
479
(6)
-
(81)
2007
$ 989
43
(5)
(423)
(84)
Presented below are the amounts included in regulatory assets and regulatory liabilities at December 31, 2008 and 2007 related to the
defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of
such amounts for 2009:
Balance at December 31, 2008:
Regulatory assets
Regulatory liabilities
Total
Balance at December 31, 2007:
Regulatory assets
Regulatory liabilities
Total
Estimated amortization in net periodic pension cost in 2009:
Regulatory assets
Regulatory liabilities
Total
Prior Service Cost Net(Gain)Loss
(in millions)
$58
-
$58
$14
56
$70
$ 9
-
$ 9
$ 421
-
$ 421
$ 29
(479)
$ (450)
$
$
1
-
1
41
NOTES (continued)
Alabama Power Company 2008 Annual Report
The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the 15-month
period ended December 31, 2008 and the 12-month period ended September 30, 2007 are presented in the following table:
Regulatory
Assets
Regulatory
Liabilities
(in millions)
Balance at December 31, 2006
Net (gain) loss
Change in prior service costs
Reclassification adjustments:
Amortization of prior service costs
Amortization of net gain
Total reclassification adjustments
Total change
Balance at December 31, 2007
Net (gain) loss
Change in prior service costs
Reclassification adjustments:
Amortization of prior service costs
Amortization of net gain
Total reclassification adjustments
Total change
Balance at December 31, 2008
$36
1
10
(2)
(2)
(4)
7
43
441
-
(2)
(3)
(5)
436
$479
$(183)
(232)
-
(8)
-
(8)
(240)
(423)
433
-
(10)
-
(10)
423
-
$
Components of net periodic pension cost (income) were as follows:
Service cost
Interest cost
Expected return on plan assets
Recognized net (gain) loss
Net amortization
Net periodic pension (income)
2008
$ 35
87
(160)
2
10
$ (26)
2007
(in millions)
$ 35
82
(146)
2
10
$ (17)
2006
$ 37
77
(139)
3
9
$ (13)
Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan
assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-
related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in
the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of
plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit
obligation for the pension plans. At December 31, 2008, estimated benefit payments were as follows:
2009
2010
2011
2012
2013
2014 to 2018
Benefit Payments
(in millions)
$ 81
84
88
92
96
556
42
NOTES (continued)
Alabama Power Company 2008 Annual Report
Other Postretirement Benefits
Changes during the 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 in the
accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets 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 (loss) on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at end of year
Funded status at end of year
Fourth quarter contributions
Accrued liability
2008
2007
(in millions)
$ 480
9
37
(30)
(53)
3
446
297
(75)
57
(27)
252
(194)
-
$(194)
$ 490
7
28
(23)
(24)
2
480
259
36
23
(21)
297
(183)
28
$(155)
Other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA
and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed
income securities, real estate, and private equity. Derivative instruments are used primarily as hedging tools but may also be used to
gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification
but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets
as of the end of year, along with the targeted mix of assets, is presented below:
Domestic equity
International equity
Fixed income
Real estate
Private equity
Total
Target
49%
12
31
5
3
100%
2008
31%
13
46
7
3
100%
2007
46%
15
29
7
3
100%
Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of:
Regulatory assets
Employee benefit obligations
2008
2007
(in millions)
$ 135
(194)
$ 95
(155)
43
NOTES (continued)
Alabama Power Company 2008 Annual Report
Presented below are the amounts included in regulatory assets at December 31, 2008 and 2007, related to the other postretirement
benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such
amounts for 2009.
Balance at December 31, 2008:
Regulatory asset
Balance at December 31, 2007:
Regulatory asset
Estimated amortization as net periodic postretirement cost in 2009:
Regulatory asset
Prior Service
Cost
Net
(Gain)Loss
(in millions)
Transition
Obligation
$49
$55
$ 4
$71
$20
$15
$20
$ -
$ 4
The change in the balance of regulatory assets related to the other postretirement benefit plans for the 15-month period ended
December 31, 2008 and the 12-month period ended September 30, 2007 are presented in the following table:
Balance at December 31, 2006
Net gain
Change in prior service costs
Reclassification adjustments:
Amortization of transition obligation
Amortization of prior service costs
Amortization of net gain
Total reclassification adjustments
Total change
Balance at December 31, 2007
Net loss
Change in prior service costs
Reclassification adjustments:
Amortization of transition obligation
Amortization of prior service costs
Amortization of net gain
Total reclassification adjustments
Total change
Balance at December 31, 2008
Regulatory
Assets
(in millions)
$147
(41)
-
(4)
(5)
(2)
(11)
(52)
95
50
-
(5)
(5)
-
(10)
40
$135
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 postretirement cost
2008
$ 7
29
(22)
9
$ 23
2007
(in millions)
$ 7
28
(19)
11
$ 27
2006
$ 7
26
(17)
12
$ 28
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug
subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31,
2008, 2007, and 2006 by approximately $10.7 million, $10.7 million, and $11.1 million, respectively.
44
NOTES (continued)
Alabama Power Company 2008 Annual Report
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions
used to measure the APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as
a result of the Medicare Act as follows:
2009
2010
2011
2012
2013
2014 to 2018
Benefit Payments
$ 28
31
33
35
36
196
Subsidy Receipts
(in millions)
$ (3)
(3)
(4)
(4)
(5)
(30)
Total
$ 25
28
29
31
31
166
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 2005 for the 2006 plan year, using a discount rate of 5.50%.
Discount
Annual salary increase
Long-term return on plan assets
2008
6.75%
3.75
8.50
2007
6.30%
3.75
8.50
2006
6.00%
3.50
8.50
The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into
account the diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.15% for 2009,
decreasing gradually to 5.50% through the year 2015, and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31,
2008 as follows:
Benefit obligation
Service and interest costs
1 Percent
Increase
1 Percent
Decrease
(in millions)
$31
2
$33
2
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85%
matching contribution up to 6% of an employee’s base salary. Prior to November 2006, the Company matched employee
contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2008, 2007,
and 2006 were $18 million, $17 million, and $14 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. 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 opacity and air and water quality standards, has increased generally throughout
the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials 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 liabilities, if any, arising
from such current proceedings would have a material adverse effect on the Company’s financial statements.
45
NOTES (continued)
Alabama Power Company 2008 Annual Report
Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain
Southern Company subsidiaries, including the Company, alleging that it had violated the New Source Review (NSR) provisions of the
Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal
procedures, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of
Alabama after the Company was dismissed from the original action. In this lawsuit, the EPA alleged that NSR violations occurred at
five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an
order requiring the installation of the best available control technology at the affected units.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the
EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required
the Company to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide
emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by the
Company, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in
Alabama granted the Company’s motion for summary judgment and entered final judgment in favor of the Company on the EPA’s
claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.
The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed,
pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke
Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Company’s case
and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the
Duke Energy case. On July 24, 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment
in favor of the Company regarding the proper legal test for determining whether projects are routine maintenance, repair, and
replacement and therefore are excluded from NSR permitting. The decision did not resolve the case and the ultimate outcome of this
matter cannot be determined at this time.
The Company believes that it complied with applicable laws and the EPA regulations and interpretations 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 at each
generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital
expenditures or affect the timing of currently budgeted 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.
Carbon Dioxide Litigation
New York Case
In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service
territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New
York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of
carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law
public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for
creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon
dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however,
requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and
notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the
Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs
filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, but no decision has been issued. The ultimate
outcome of these matters cannot be determined at this time.
46
NOTES (continued)
Alabama Power Company 2008 Annual Report
Kivalina Case
On February 26, 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern
District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The
plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion
allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs
assert claims for public and private nuisance and contend that the defendants have acted in concert and are therefore jointly and
severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village,
which is alleged to be $95 million to $400 million. On June 30, 2008, all defendants filed motions to dismiss this case. Southern
Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Remediation
The Company must comply with other 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 may also incur substantial costs to clean up
properties. The Company has received authority from the Alabama PSC to recover approved environmental compliance costs through
a specific retail rate clause that is adjusted annually. See “Retail Regulatory Matters – Rate CNP” herein for additional information.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based
prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service
territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales
by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006
could be subject to refund to a cost-based rate level.
In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the
generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot
now be determined, but an adverse decision by the FERC in a final order could require the Company to charge cost-based rates for
certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and
could also result in total refunds of up to $3.9 million, plus interest. The Company believes that there is no meritorious basis for an
adverse decision in this proceeding and is vigorously defending itself in this matter.
In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its
current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April
21, 2008 and Order No. 697-B on December 12, 2008. These orders largely affirmed the FERC’s prior revision and codification of
the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the
FERC an updated market power analysis on September 2, 2008 related to its continued market-based rate authority. The ultimate
outcome of this matter cannot now be determined.
On October 17, 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate
(CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its
available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after
considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales
under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a
cost-based price for wholesale sales of less than a year. On December 18, 2008, the FERC issued an order conditionally accepting the
MBR tariff subject to certain revisions to the auction proposal. On January 21, 2009, Southern Company made a compliance filing
that accepted all the conditions of the MBR tariff order. When this order becomes final, Southern Company will have 30 days to
implement the wholesale auction. On December 31, 2008, the FERC issued an order conditionally accepting the CBR tariff subject to
providing additional information concerning one aspect of the tariff. On January 30, 2009, Southern Company filed a response
addressing the FERC inquiry to the CBR tariff order. Implementation of the energy auction in accordance with the MBR tariff order
47
NOTES (continued)
Alabama Power Company 2008 Annual Report
is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern
Company retail service territory. The timing of when the FERC may issue the final orders on the MBR and CBR tariffs and the
ultimate outcome of these matters cannot be determined at this time.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May
2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies
(including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is
operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are
transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather
than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized
Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement
to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications.
The modifications largely involve functional separation and information restrictions related to marketing activities conducted on
behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the
order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of
the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the
FERC that the plan had been implemented. On December 12, 2008, the FERC division of audits issued, for public comment, its final
audit report pertaining to compliance implementation and related matters. No comments challenging the audit report’s findings were
submitted. A decision is now pending from the FERC.
Generation Interconnection Agreements
In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to two previously executed
interconnection agreements with the Company, filed complaints at the FERC requesting that the FERC modify the agreements and
that the Company refund a total of $11 million previously paid for interconnection facilities. No other similar complaints are pending
with the FERC.
In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification
of Tenaska’s interconnection agreements, under the provisions of the order, the Company determined that no refund was payable to
Tenaska. The Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection
agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings
were denied and the Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final
outcome of this matter cannot now be determined.
Retail Regulatory Matters
The following retail ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.
Rate RSE
The Alabama PSC has adopted a Rate Stabilization and Equalization plan (Rate RSE) that provides for periodic annual adjustments
based upon the Company’s earned return on retail common equity. Retail rates remain unchanged when the retail return on common
equity ranges between 13.0% and 14.5%. In October 2005, the Alabama PSC approved a revision to Rate RSE. Effective January
2007 and thereafter, Rate RSE adjustments are made 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% per year and any annual adjustment is
limited to 5.0%. Prior to January 2007, annual adjustments were limited to 3.0%. Retail rates remain unchanged when the return on
retail common equity is projected to be between 13.0% and 14.5%. If the Company’s actual retail return on common equity 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 on common equity fall below the allowed equity return range. The Rate RSE increase for 2008 was
3.24% or $147 million annually and was effective in January 2008.
48
NOTES (continued)
Alabama Power Company 2008 Annual Report
On October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for adjustments associated with
customer charges to certain existing rate structures. This package, effective in January 2009, is expected to generate additional annual
revenues of approximately $168 million. The Company agreed to a moratorium on any increase in rates in 2009 under Rate RSE. On
December 1, 2008, the Company made its submission of projected data for calendar year 2009.
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 and the recovery of retail costs associated with certificated PPAs under a Rate Certificated New Plant (Rate
CNP). In April 2006, an annual adjustment to Rate CNP increased retail rates by approximately 0.5% or $19 million annually. There
was no rate adjustment associated with the annual true-up adjustment in April 2007 and 2008. There will be no adjustment to the
current Rate CNP to recover certificated PPA costs in April 2009.
Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such
mandates. The rate mechanism 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 invested capital. Retail rates increased due to environmental costs approximately 1.2% in January 2006, 0.6% in
January 2007, and 2.4% in January 2008. On October 7, 2008, the Company agreed to defer collection during 2009 of any increase in
rates under the portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations until 2010.
The deferral of the retail rate adjustments will have an immaterial impact on annual cash flows, and will have no significant effect on
the Company’s revenues or net income. On December 1, 2008, the Company made its submission of projected data for calendar year
2009.
Fuel Cost Recovery
The Company has established fuel cost recovery rates under an energy cost recovery clause (Rate ECR) approved by the Alabama
PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. The Company, along
with the Alabama PSC, will continue to monitor the under recovered fuel cost balance to determine whether an additional adjustment
to billing rates is required.
In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per kilowatt-hour (KWH)
effective with billings beginning July 2007 for the 30-month period ending December 2009. The previous rate of 2.400 cents per
KWH had been in effect since January 2006. This increase was intended to permit recovery of energy costs based on an estimate of
future energy cost, as well as the collection of the existing under recovered energy cost by the end of 2009. During the recovery
period, the Company was allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense
calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, the
Company would pay interest on any such over recovered balance at the same rate used to derive the carrying cost.
On October 7, 2008, the Alabama PSC approved an increase in the Company’s Rate ECR factor to 3.983 cents per KWH for a 24-
month period beginning with October 9, 2008 billings. Thereafter, the Rate ECR factor is 5.910 cents per KWH, absent a contrary
order by the Alabama PSC. The previous rate of 3.100 cents per KWH had been in effect since July 2007. Rate ECR revenues, as
recorded on the financial statements, are adjusted for the difference in actual recoverable costs and amounts billed in current regulated
rates. During the 24-month period, the Company will be allowed to continue to include a carrying charge associated with the under
recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over
recovered position during this period, the Company will pay interest on any such over recovered balance at the same rate used to
derive the carrying cost.
The Company’s under recovered fuel costs as of December 31, 2008 totaled $305.8 million as compared to $279.8 million at
December 31, 2007. As a result of the Alabama PSC orders, the Company classified $180.9 million and $81.7 million of the under
recovered regulatory clause revenues as deferred charges and other assets in the balance sheets as of December 31, 2008 and
December 31, 2007, respectively. This classification is based on an estimate which includes 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
the recovery of the under recovered fuel costs.
49
NOTES (continued)
Alabama Power Company 2008 Annual Report
Natural Disaster Cost Recovery
Based on an order by 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.
In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR due to the hurricanes in
2005 and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit
balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a
separate monthly NDR charge consisting of two components which began in January 2006. The first component is intended to
establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The
Company currently expects that the target reserve balance could be achieved within three years. The second component of the NDR
charge is intended to allow recovery of the existing deferred hurricane related operations and maintenance costs and any future reserve
deficits over a 24-month period. Absent further Alabama PSC approval, the maximum total NDR charge consisting of both
components is $10 per month per non-residential customer account and $5 per month per residential customer account.
At December 31, 2008, the Company had an accumulated balance of $33.2 million in the target reserve for future storms, which is
included in the balance sheets under “Other Regulatory Liabilities.” In June 2007, the Company fully recovered its storm cost of
$51.3 million resulting from previous hurricanes. As a result, customer rates decreased by this portion of the NDR charge effective in
July 2007.
As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expense related to the NDR will also
be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase annual cash
flow.
Nuclear Fuel Disposal Costs
The Company has a contract with the United States, acting through the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contract,
and the Company is pursuing legal remedies against the government for breach of contract.
In July 2007, the U.S. Court of Federal Claims awarded the Company approximately $17 million, representing substantially all of the
direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In July 2007, the
government filed a motion for reconsideration, which was denied in November 2007. On January 2, 2008, the government filed an
appeal, and on February 29, 2008, filed a motion to stay the appeal. On April 1, 2008, the court granted the government’s motion to
stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008.
Based on the rulings in those cases, the appeal is expected to proceed in first quarter 2009.
On April 3, 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-
mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. On October 31, 2008, the
court denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount
for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts
have been recognized in the financial statements as of December 31, 2008 for either claim. The final outcome of these matters cannot
be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government
are expected to be returned to customers.
An on-site dry spent fuel storage facility at Plant Farley is operational and can be expanded to accommodate spent fuel through the
expected life of the plant.
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 megawatts, as well as associated transmission facilities. The capacity of these units is sold equally
to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating
expenses, taxes, interest expense, and a return on equity, whether or not SEGCO has any capacity and energy available. The term of
the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two years’ notice. The
50
NOTES (continued)
Alabama Power Company 2008 Annual Report
Company’s share of purchased power totaled $124 million in 2008, $105 million in 2007, and $95 million in 2006, 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 $24.5 million principal amount of
pollution control revenue bonds are outstanding. Also, the Company has guaranteed $50 million principal amount of unsecured senior
notes issued by SEGCO for general corporate purposes. 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 guaranty.
At December 31, 2008, the capitalization of SEGCO consisted of $68 million of equity and $74 million of long-term debt on which
the annual interest requirement is $3.2 million. SEGCO paid dividends totaling $7.8 million in 2008, $2.6 million in 2007, and
$8.5 million in 2006, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO’s net
income.
In addition to the Company’s ownership of SEGCO, the Company’s percentage ownership and investment in jointly-owned coal-fired
generating plants at December 31, 2008 is as follows:
Facility
Total Megawatt
Capacity
Company
Ownership
Company
Investment
Accumulated
Depreciation
Greene County
Plant Miller
Units 1 and 2
(1) Jointly owned with an affiliate, Mississippi Power.
(2) Jointly owned with PowerSouth.
1,320
500
(in millions)
60.00% (1)
$130
91.84% (2)
986
$68
425
At December 31, 2008, the Company’s Plant Miller portion of construction work in progress was $174.4 million.
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
Southern Company files a consolidated federal income tax return and combined income tax returns for the State of Georgia, State of
Mississippi, and the State of Alabama. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and
deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more 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 tax liability.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
Federal –
Current
Deferred
State –
Current
Deferred
Total
2008
2007
(in millions)
$198
121
319
43
6
49
$368
$287
17
304
43
4
47
$351
2006
$302
(25)
277
56
(3)
53
$330
51
NOTES (continued)
Alabama Power Company 2008 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
Pension and other benefits
Fuel clause under recovered
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
State effect of federal deferred taxes
Unbilled revenue
Storm reserve
Pension and other benefits
Other comprehensive losses
Regulatory liabilities associated with employee benefit obligations
Asset retirement obligations
Other
Total
Total deferred tax liabilities, net
Portion included in current (liabilities) assets, net
Accumulated deferred income taxes in the balance sheets
2008
2007
(in millions)
$1,908
343
33
175
140
286
-
199
67
3,151
126
104
34
4
330
13
-
199
82
892
2,259
(16)
$2,243
$1,766
341
36
340
128
90
27
187
60
2,975
121
96
31
3
126
10
178
214
88
867
2,108
(43)
$2,065
At December 31, 2008, the Company’s tax-related regulatory assets and liabilities were $363 million and $90 million, respectively.
These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest.
These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to
unamortized investment tax credits.
In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives 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 $8.0 million in 2008, 2007, and 2006. At December 31, 2008, all investment tax credits available to reduce federal
income taxes payable had been utilized.
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
Production activities deduction
Other
Effective income tax rate
2008
35.0%
3.1
0.9
(0.1)
(1.6)
(0.5)
(0.8)
36.0%
2007
35.0%
3.2
0.9
(0.2)
(1.3)
(0.6)
(0.7)
36.3%
2006
35.0%
4.0
1.0
(0.3)
(0.7)
(0.2)
(0.9)
37.9%
52
NOTES (continued)
Alabama Power Company 2008 Annual Report
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U. S. production activities as
defined in Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of
qualified production activities income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the
years 2005 and 2006, a 6% rate applicable for years 2007 through 2009, and a 9% rate thereafter. The increase from 3% in 2006 to
6% in 2007 was one of several factors that increased the Company’s 2007 deduction by $7.8 million over the 2006 deduction. The
resulting additional tax benefit was approximately $3 million. The IRS has not clearly defined a methodology for calculating this
deduction. However, Southern Company has agreed with the IRS on a calculation methodology and signed a closing agreement on
December 11, 2008. Therefore, the Company reversed the unrecognized tax benefit and adjusted the deduction for all previous years
to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. The net
impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect
on the Company’s financial statements.
Unrecognized Tax Benefits
FIN 48 requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by
the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance
on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. For
2008, the total amount of unrecognized tax benefits decreased by $1.8 million, resulting in a balance of $3.0 million as of December
31, 2008.
Changes during the year in unrecognized tax benefits were as follows:
Unrecognized tax benefits at beginning of year
Tax positions from current periods
Tax positions from prior periods
Reductions due to settlements
Reductions due to expired statute of limitations
Balance at end of year
2008
(in millions)
$4.8
0.8
(1.4)
(1.2)
-
$3.0
2007
$1.2
1.5
2.1
-
-
$4.8
The reduction due to settlements relates to the agreement with the IRS regarding the production activities deduction methodology.
See “Effective Tax Rate” above for additional information.
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
Accrued interest for unrecognized tax benefits:
Interest accrued at beginning of year
Interest reclassified due to settlements
Interest accrued during the year
Balance at end of year
2008
$3.0
-
$3.0
2007
(in millions)
$4.8
-
$4.8
Change
$(1.8)
-
$(1.8)
2008
(in millions)
$0.4
(0.3)
0.2
$0.3
2007
$ -
-
0.4
$0.4
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax
positions.
It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of the Company’s unrecognized tax
positions will significantly increase or decrease within the next 12 months. The possible conclusion or settlement of federal or state
audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be
determined.
53
NOTES (continued)
Alabama Power Company 2008 Annual Report
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute
of limitations has expired, for years prior to 2002.
6. FINANCING
Long-Term Debt Payable to Affiliated Trusts
The Company has formed certain wholly owned trust subsidiaries 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, which constitute substantially all assets of these trusts 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 respective trusts’ payment obligations with respect to these
securities. At December 31, 2008, preferred securities of $200 million were outstanding. See Note 1 under “Variable Interest
Entities” for additional information on the accounting treatment for these trusts and the related securities.
Securities Due Within One Year
At December 31, 2008, the Company had scheduled maturities and redemptions of senior notes due within one year totaling
$250 million. At December 31, 2007, the Company had scheduled maturities and redemptions of senior notes, and preferred stock due
within one year totaling $535 million.
Maturities of senior notes through 2013 applicable to total long-term debt are as follows: $250 million in 2009; $100 million in 2010;
$200 million in 2011; $500 million in 2012; and $250 million in 2013.
Pollution Control Revenue Bonds
Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of 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 obligations
related to the issuance of $254 million of pollution control revenue bonds in 2008. Proceeds from certain issuances are restricted until
expenditures are incurred. During 2008, the Company was required to purchase a total of approximately $11 million of variable rate
pollution control revenue bonds that were tendered by investors, all of which were subsequently remarketed.
Also, during 2008, the Company entered into $330 million notional amount of interest rate swaps related to variable rate pollution
control revenue bonds to hedge changes in interest rate for the period February 2008 through February 2010. The weighted average
fixed payment rate on these hedges is 2.49% and the Company now has a total of $576 million of such hedges in place, with an overall
weighted average fixed payment rate of 2.69%.
Senior Notes
The Company issued a total of $850 million of unsecured senior notes in 2008. The proceeds of these issuances were used to repay
short-term indebtedness and for other general corporate purposes.
At December 31, 2008 and 2007, the Company had $4.6 billion and $4.1 billion, respectively, of senior notes outstanding. These
senior notes are subordinate to all secured debt of the Company which amounted to approximately $153 million at December 31,
2008.
Preference and Common Stock
In 2008, the Company issued no new shares of preference stock. The Company issued 7.5 million new shares of common stock to
Southern Company at $40.00 per share and realized proceeds of $300 million. The proceeds of these issuances were used for general
corporate purposes.
54
NOTES (continued)
Alabama Power Company 2008 Annual Report
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 or involuntary dissolution. The Company’s
preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution.
Certain series of the preferred stock, Class A preferred stock, and preference stock are subject to redemption at the option of the
Company on or after a specified date (typically 5 or 10 years after the date of issuance).
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, 2008.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $1.3 billion (including $582 million of such lines which are
dedicated to funding purchase obligations relating to variable rate pollution control revenue bonds), of which $466 million will expire
at various times during 2009. $379 million of the credit facilities expiring in 2009 allow for the execution of one-year term loans.
$765 million of credit facilities expire in 2012.
Most of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the
maintenance of compensating balances with the banks. Commitment fees average less than one-fourth 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, 2008, the Company was in compliance with the debt limit covenants. In addition, the credit arrangements typically
contain cross default provisions that would be triggered if the Company defaulted on other indebtedness (including guarantee
obligations) above a specified threshold. None of the arrangements contain material adverse change clauses at the time of borrowings.
The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. In
addition, the Company borrows from time to time through uncommitted credit arrangements. As of December 31, 2008, the Company
had $25 million of commercial paper outstanding. As of December 31, 2007, the Company had no commercial paper outstanding.
During 2008 and 2007, the peak amount outstanding for short-term borrowings was $301 million and $214 million, respectively. The
average amount outstanding in 2008 and 2007 was $40 million and $36 million, respectively. The average annual interest rate on
short-term borrowings in 2008 was 2.31% and in 2007 was 5.34%. Short-term borrowings are included in notes payable in the
balance sheets.
At December 31, 2008, the Company had regulatory approval to have outstanding up to $2.0 billion of short-term borrowings.
Financial Instruments
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, the Company has limited exposure to market volatility in commodity fuel prices and prices of
electricity. The Company manages a fuel-hedging program implemented per the guidelines of the Alabama PSC. The Company also
enters into hedges of forward electricity sales.
55
NOTES (continued)
Alabama Power Company 2008 Annual Report
At December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial
statements as assets/(liabilities) as follows:
Regulatory hedges
Cash flow hedges
Non-accounting hedges
Total fair value
2008
(in millions)
$(91.9)
-
-
$(91.9)
2007
$(0.7)
0.5
(0.2)
$(0.4)
Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging
program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel
expenses as they are recovered through the fuel cost recovery clauses. 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 transactions. 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. There was no material ineffectiveness recorded in earnings for any period
presented. The Company has energy-related hedges in place up to and including 2012.
The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities
or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to
minimize ineffectiveness. As such, no material ineffectiveness has been recorded in earnings for any period presented.
At December 31, 2008, the Company had $576 million notional amount of interest rate derivatives outstanding that related to variable
rate tax exempt debt, with net fair value losses of approximately $11 million as follows:
Notional
Amount
Variable
Rate
Received
Weighted
Average
Fixed Rate Paid
Hedge
Maturity
Date
Fair Value
Gain (Loss)
December 31, 2008
(in millions)
$576 million
$(11)
* Hedged using the Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA),
February 2010
2.69%*
SIFMA
Index
(formerly the Bond Market Association/PSA Municipal Swap Index)
The fair value gain or loss for cash flow hedges are recorded in other comprehensive income and are reclassified into earnings at the
same time the hedged items affect earnings. In 2007 and 2006, the Company settled gains/(losses) of $(6) million, and $18 million,
respectively, upon termination of certain interest derivatives at the same time it issued debt and did not incur any such settlement
gains/(losses) in 2008. The effective portions of these gains/(losses) have been deferred in other comprehensive income and will be
amortized to interest expense over the life of the original interest derivative, which approximates to the related underlying debt.
For the years 2008, 2007, and 2006, approximately $(3) million, $(1) million, and $10 million, respectively, of pre-tax gains/(losses)
were reclassified from other comprehensive income to interest expense. For 2009, pre-tax losses of approximately $8 million are
expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place
through 2010 and has deferred realized gains/(losses) that are being amortized through 2035.
All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. See Note 10 for
additional information.
7. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated to total $1.4 billion in 2009, $1.0 billion in 2010,
and $1.0 billion in 2011. These amounts include $48 million, $37 million, and $45 million in 2009, 2010, and 2011, respectively, for
construction expenditures related to contractual purchase commitments for nuclear fuel included under “Fuel Commitments.” The
construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates
56
NOTES (continued)
Alabama Power Company 2008 Annual Report
because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in
environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and
regulations; Alabama PSC approvals; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital.
In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2008,
significant purchase commitments were outstanding in connection with the construction program. The Company has no generating
plants under construction. Construction of new transmission and distribution facilities and capital improvements, including those
needed to meet environmental standards for existing generation, transmission, and distribution facilities, will continue.
Long-Term Service Agreements
The Company has entered into Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing
maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs provide that GE will perform all
planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the
costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.
In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE, which are subject to
price escalation, are made at various intervals based on actual operating hours of the respective units. Total remaining payments to
GE under these agreements for facilities owned are currently estimated at $119 million over the remaining life of the agreements,
which are currently estimated to range up to 8 years. However, the LTSAs contain various cancellation provisions at the option of the
Company. Payments made to GE prior to the performance of any planned maintenance are recorded as either prepayments or other
deferred charges and assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the
work performed.
Limestone Commitments
As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has begun construction of
flue gas desulfurization projects and has entered into various long-term commitments for the procurement of limestone to be used in
such equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in
coal burn and sulfur content. The Company has a minimum contractual obligation of 3.0 million tons equating to approximately $124
million through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $3
million in 2009, $10 million in 2010, $14 million in 2011, $14 million in 2012, and $15 million in 2013.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments
for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and
nitrogen oxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at
the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices
at December 31, 2008. Total estimated minimum long-term commitments at December 31, 2008 were as follows:
2009
2010
2011
2012
2013
2014 and thereafter
Total commitments
Natural Gas
$ 505
266
120
154
157
210
$1,412
Commitments
Coal
(in millions)
$1,461
996
808
636
474
1,414
$5,789
Nuclear Fuel
$ 48
37
45
44
32
10
$216
Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in
fuel expense totaled $70 million in 2008, $65 million in 2007, and $66 million in 2006.
57
NOTES (continued)
Alabama Power Company 2008 Annual Report
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 traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and
Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the
creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into 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.
Purchased Power Commitments
The Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term
obligations at December 31, 2008 were as follows:
2009
2010
2011
2012
2013
2014 and thereafter
Total commitments
Affiliated
$61
17
-
-
-
-
$78
Commitments
Non-Affiliated
(in millions)
$44
24
3
-
-
-
$71
Total
$105
41
3
-
-
-
$149
Operating Leases
The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration
dates. These expenses totaled $26.1 million in 2008, $27.7 million in 2007, and $30.3 million in 2006. Of these amounts,
$19.2 million, $20.5 million, and $21.5 million for 2008, 2007, and 2006, respectively, relate to the rail car leases and are recoverable
through the Company’s Rate ECR. At December 31, 2008, estimated minimum rental commitments for non-cancelable operating
leases were as follows:
2009
2010
2011
2012
2013
2014 and thereafter
Total
Rail Cars
$17
13
5
5
4
11
$55
Minimum Lease Payments
Vehicles & Other
(in millions)
$6
6
4
2
1
-
$19
Total
$23
19
9
7
5
11
$74
Subsequent to December 31, 2008, the Company entered into rental agreements for coal rail cars resulting in the minimum lease
commitments above increasing by $3 million in 2009, $4 million in 2010, $2 million in 2011, and $1 million each in years 2012 and
2013.
In addition to the rental commitments above, the Company has potential obligations upon expiration of certain leases with respect to
the residual value of the leased property. These leases expire in 2010 and 2013, and the Company’s maximum obligations are
$61.2 million and $18.6 million, respectively. At the termination of the leases, at the Company’s option, the Company may negotiate
an extension, 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 eliminate the Company’s payments under the residual value obligations.
Guarantees
At December 31, 2008, the Company had outstanding guarantees related to SEGCO’s purchase of certain pollution control facilities
and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets as described above in “Operating
Leases.”
58
NOTES (continued)
Alabama Power Company 2008 Annual Report
8. STOCK OPTION PLAN
Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line
management to executives. As of December 31, 2008, there were 1,267 current and former employees of the Company participating
in the stock option plan and there were 33.2 million shares of common stock remaining available for awards under this plan. The
prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date 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 stock option plan. For certain
stock option awards, a change in control will provide accelerated vesting.
The estimated fair values of stock options granted in 2008, 2007, and 2006 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.
The 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
2008
13.1%
5.0
2.8%
4.5%
$2.37
2007
14.8%
5.0
4.6%
4.3%
$4.12
2006
16.9%
5.0
4.6%
4.4%
$4.15
The Company’s activity in the stock option plan for 2008 is summarized below:
Outstanding at December 31, 2007
Granted
Exercised
Cancelled
Outstanding at December 31, 2008
Exercisable at December 31, 2008
Shares Subject
to Option
6,186,430
1,148,493
(522,381)
(3,346)
6,809,196
4,610,589
Weighted Average
Exercise Price
$30.50
35.78
27.68
32.31
$31.61
$29.65
The number of stock options vested and expected to vest in the future, as of December 31, 2008 was not significantly different from
the number of stock options outstanding at December 31, 2008 as stated above. As of December 31, 2008, the weighted average
remaining contractual term for the options outstanding and options exercisable was 6.1 years and 5.0 years, respectively, and the
aggregate intrinsic value for the options outstanding and options exercisable was $36.7 million and $33.9 million, respectively.
As of December 31, 2008, there was $1.1 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 10 months.
For the years ended December 31, 2008, 2007 and 2006, total compensation cost for stock option awards recognized in income was
$3.1 million, $4.9 million and $4.8 million, respectively, with the related tax benefit also recognized in income of $1.2 million, $1.9
million and $1.9 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.
59
NOTES (continued)
Alabama Power Company 2008 Annual Report
The total intrinsic value of options exercised during the years ended December 31, 2008, 2007, and 2006 was $5.2 million,
$9.7 million, and $4.9 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option
exercises totaled $2.0 million, $3.7 million, and $1.9 million, respectively, for the years ended December 31, 2008, 2007, and 2006.
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
$12.5 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a
maximum of $300 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 $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of
$17.5 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 $235 million per incident but not more than an aggregate of $35 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 October 29, 2013.
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’ nuclear generating facilities.
Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature
decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also
provided by NEIL.
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 the maximum
limit allowed by NEIL and has elected a 12-week waiting period.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to
the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be
$39 million.
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 bond trustees as may be appropriate under the
policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state
premium taxes.
10. FAIR VALUE MEASUREMENTS
On January 1, 2008, the Company adopted FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) which defines
fair value, establishes a framework for measuring fair value, and requires additional disclosures about fair value measurements.
The criterion that is set forth in SFAS No. 157 is applicable to fair value measurement where it is permitted or required under other
accounting pronouncements.
SFAS No. 157 defines fair value as the exit price, which is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the measurement date. The fair value measurement is 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. As a
60
NOTES (continued)
Alabama Power Company 2008 Annual Report
means to illustrate the inputs used, SFAS No. 157 establishes a three-tier fair value hierarchy that prioritizes inputs to valuation
techniques used for fair value measurement.
(cid:120) Level 1 consists of observable market data in an active market for identical assets or liabilities.
(cid:120) Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly
observable.
(cid:120) 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.
The adoption of SFAS No. 157 has not resulted in any significant changes to the methodologies used for fair value measurement.
Primarily all the changes in the fair value of assets and liabilities are recorded in other comprehensive income or regulatory assets
and liabilities, and thus the impact on earnings is limited to derivatives that do not qualify for hedge accounting.
The fair value measurements performed on a recurring basis and the level of the fair value hierarchy in which they fall at
December 31, 2008 are as follows:
At December 31, 2008:
Level 1
Level 2
Level 3
Total
Assets:
Energy-related derivatives
Nuclear decommissioning trusts(a)
Cash equivalents and restricted cash
Total fair value
Liabilities:
Energy-related derivatives
Interest rate derivatives
Total fair value
(in millions)
$
-
237.4
80.1
$ 317.5
$ 3.6
165.5
-
$169.1
$
$
$
$
-
-
-
$ 95.5
10.9
$106.4
$
$
-
-
-
-
-
-
-
$ 3.6
402.9
80.1
$486.6
$ 95.5
10.9
$106.4
(a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note 6 under
“Financial Instruments” for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of
equity and fixed income securities. See Note 1 under “Nuclear Decommissioning” for additional information. The cash
equivalents and restricted cash consist of securities with original maturities of 90 days or less. All of these financial instruments
and investments are valued primarily using the market approach.
11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2008 and 2007 are as follows:
Quarter Ended
March 2008
June 2008
September 2008
December 2008
March 2007
June 2007
September 2007
December 2007
Operating
Revenues
$1,337
1,470
1,865
1,405
$1,197
1,336
1,635
1,192
The Company’s business is influenced by seasonal weather conditions.
61
Operating
Income
(in millions)
Net Income After
Dividends on Preferred
and Preference Stock
$274
319
478
198
$255
311
476
173
$130
153
252
81
$115
147
246
72
SELECTED FINANCIAL AND OPERATING DATA 2004-2008
Alabama Power Company 2008 Annual Report
Operating Revenues (in thousands)
Net Income after Dividends
2008
$6,076,931
2007
$5,359,993
2006
$5,014,728
2005
$4,647,824
2004
$4,235,991
on Preferred and Preference Stock (in thousands)
$615,959
$579,582
$517,730
$507,895
$481,171
Cash Dividends
on Common Stock (in thousands)
Return on Average Common Equity (percent)
Total Assets (in thousands)
Gross Property Additions (in thousands)
Capitalization (in thousands):
Common stock equity
Preferred and preference stock
Long-term debt
Total (excluding amounts due within one year)
Capitalization Ratios (percent):
Common stock equity
Preferred and preference stock
Long-term debt
Total (excluding amounts due within one year)
Security Ratings:
First Mortgage Bonds -
Moody's
Standard and Poor's
Fitch
Preferred Stock/ Preference Stock -
Moody's
Standard and Poor's
Fitch
Unsecured Long-Term Debt -
Moody's
Standard and Poor's
Fitch
Customers (year-end):
Residential
Commercial
Industrial
Other
Total
Employees (year-end)
$465,000
13.73
$491,300
13.30
$437,300
13.53
$16,536,006 $15,746,625 $14,655,290 $13,689,907 $12,781,525
$786,298
$1,532,673
$440,600
13.23
$409,900
13.72
$1,203,300
$890,062
$960,759
$4,854,310
685,127
5,604,791
$11,144,228
$4,410,683
683,512
4,750,196
$9,844,391
$4,032,287
612,407
4,148,185
$8,792,879
$3,792,726
465,046
3,869,465
$8,127,237
$3,610,204
465,047
4,164,536
$8,239,787
43.6
6.1
50.3
100.0
-
-
-
Baa1
BBB+
A
A2
A
A+
44.8
6.9
48.3
100.0
-
-
-
Baa1
BBB+
A
A2
A
A+
45.9
7.0
47.1
100.0
-
-
-
Baa1
BBB+
A
A2
A
A+
46.7
5.7
47.6
100.0
A1
A+
AA-
Baa1
BBB+
A
A2
A
A+
43.8
5.6
50.6
100.0
A1
A
AA-
Baa1
BBB+
A
A2
A
A+
1,220,046
211,119
5,906
775
1,437,846
6,997
1,207,883
216,830
5,849
772
1,431,334
6,980
1,194,696
214,723
5,750
766
1,415,935
6,796
1,184,406
212,546
5,492
759
1,403,203
6,621
1,170,814
208,547
5,260
753
1,385,374
6,745
62
SELECTED FINANCIAL AND OPERATING DATA 2004-2008 (continued)
Alabama Power Company 2008 Annual Report
Operating Revenues (in thousands):
Residential
Commercial
Industrial
Other
Total retail
Wholesale - non-affiliates
Wholesale - affiliates
Total revenues from sales of electricity
Other revenues
Total
Kilowatt-Hour Sales (in thousands):
Residential
Commercial
Industrial
Other
Total retail
Sales for resale - non-affiliates
Sales for resale - 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
2008
2007
2006
2005
2004
$1,997,603
1,459,466
1,381,100
24,112
4,862,281
711,903
308,482
5,882,666
194,265
$6,076,931
18,379,801
14,551,495
22,074,616
201,283
55,207,195
15,203,960
5,256,130
75,667,285
10.87
10.03
6.26
8.81
4.99
7.77
$1,833,563
1,313,642
1,238,368
21,383
4,406,956
627,047
144,089
5,178,092
181,901
$5,359,993
18,874,039
14,761,243
22,805,676
200,874
56,641,832
15,769,485
3,241,168
75,652,485
9.71
8.90
5.43
7.78
4.06
6.84
$1,664,304
1,172,436
1,140,225
18,766
3,995,731
634,552
216,028
4,846,311
168,417
$5,014,728
18,632,935
14,355,091
23,187,328
199,445
56,374,799
15,978,465
5,145,107
77,498,371
8.93
8.17
4.92
7.09
4.03
6.25
$1,476,211
1,062,341
1,065,124
17,745
3,621,421
551,408
288,956
4,461,785
186,039
$4,647,824
18,073,783
14,061,650
23,349,769
198,715
55,683,917
15,442,728
5,735,429
76,862,074
8.17
7.55
4.56
6.50
3.97
5.80
$1,346,669
980,771
948,528
16,860
3,292,828
483,839
308,312
4,084,979
151,012
$4,235,991
17,368,321
13,822,926
22,854,399
198,253
54,243,899
15,483,420
7,233,880
76,961,199
7.75
7.10
4.15
6.07
3.49
5.31
15,162
15,696
15,663
15,347
14,894
$1,648
$1,525
$1,399
$1,253
$1,155
12,222
12,222
12,222
12,216
12,216
10,144
12,211
59.4
88.2
87.5
60.9
16.5
1.8
8.7
1.8
10.3
100.0
10,309
11,744
61.8
89.6
93.3
60.2
17.4
3.8
7.6
2.1
8.9
100.0
9,812
11,162
63.2
90.5
92.9
59.5
17.2
5.6
6.8
3.8
7.1
100.0
9,556
10,938
63.2
87.8
88.7
56.5
16.4
5.6
8.9
5.4
7.2
100.0
10,747
11,518
60.9
90.08
94.13
58.5
17.8
2.9
9.2
2.9
8.7
100.0
63
DIRECTORS AND OFFICERS
Alabama Power Company 2008 Annual Report
Directors
Whit Armstrong
President, Chairman and CEO
The Citizens Bank
Ralph D. Cook 1
Attorney
Hare, Wynn, Newell & Newton
David J. Cooper, Sr.
Vice Chairman
Cooper/T. Smith Corporation
John D. Johns
Chairman, President and CEO
Protective Life Corporation
Patricia M. King
President and CEO
Sunny King Automotive Group
James K. Lowder
Chairman
The Colonial Company
Charles D. McCrary
President and CEO
Alabama Power Company
Malcolm Portera
Chancellor
The University of Alabama
System
Robert D. Powers
President
The Eufaula Agency, Inc.
David M. Ratcliffe
Chairman, President and CEO
Southern Company
C. Dowd Ritter
Chairman, President and CEO
Regions Financial Corporation
James H. Sanford
Chairman
HOME Place Farms, Inc.
John C. Webb, IV
President
Webb Lumber Company, Inc.
James W. Wright
Chairman
First Tuskegee Bank
Officers
Charles D. McCrary
President and Chief Executive
Officer
Art P. Beattie
Executive Vice President, Chief
Financial Officer and Treasurer
Mark A. Crosswhite
Executive Vice President
Steve R. Spencer
Executive Vice President
Gordon G. Martin
Senior Vice President and
General Counsel
Robert Holmes, Jr.
Senior Vice President
Robin A. Hurst
Senior Vice President
Michael L. Scott
Senior Vice President
Jerry L. Stewart
Senior Vice President
Moses H. Feagin 2
Vice President and Comptroller
William E. Zales, Jr.
Vice President, Corporate
Secretary and Assistant Treasurer
Kathleen S. King 3
Vice President, Chief Information
Officer
Greg Barker
Vice President
Robert Bell 4
Vice President
Matthew W. Bowden5
Vice President
Willard L. Bowers
Vice President
Kenneth E. Coleman 6
Vice President, Southern Division
J. Leigh Davis
Vice President
`
Larry R. Grill
Vice President
Gerald L. Johnson
Vice President, Birmingham
Division
Marsha S. Johnson 7
Vice President
William B. Johnson
Vice President
64
Bobby J. Kerley
Vice President
Barbara J. Knight
Vice President
Myrna J. Pittman
Vice President
Leslie L. Sanders
Vice President
R. Michael Saxon
Vice President, Southeast Division
Julia H. Segars
Vice President, Eastern Division
Nicholas C. Sellers 8
Vice President
Julian H. Smith, Jr. 9
Vice President
Zeke W. Smith
Vice President
Cheryl A. Thompson
Vice President, Mobile Division
Terry H. Waters
Vice President, Western Division
Anita Allcorn-Walker
Assistant Comptroller
Ronald Q. Patterson
Assistant Comptroller
E. Wayne Boston
Assistant Secretary and
Assistant Treasurer
Ceila H. Shorts
Assistant Secretary
Kay I. Worley
Assistant Secretary
J. Randy DeRieux
Assistant Treasurer
1 Elected 7/08
2 Effective 5/08
3 Elected 10/08
4 Retired 4/08
5 Elected 1/09
6 Elected 4/08
7 Elected 4/08
8 Elected 4/08
9 Retired 6/08
CORPORATE INFORMATION
Alabama Power Company 2008 Annual Report
report
General
This annual
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.
is submitted
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
the
Southeast. The Company sells electricity to more
than 1.4 million customers within its service area of
approximately 45,000 square miles. In 2008, retail
energy sales accounted for 73 percent of the
Company’s total sales of 76 billion kilowatt-hours.
to wholesale customers
in
The 5.30% Series Class A Preferred Stock
The Bank of New York Mellon
Shareowner Services
480 Washington Boulevard
Jersey City, NJ 07310-1900
Number of Preferred and Preference Shareholders
of record as of December 31, 2008 was 1,503.
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) 257-3385.
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.
Alabama Power Company
600 North 18th Street
Birmingham, AL 35203
(205) 257-1000
www.alabamapower.com
Trustee, Registrar and Interest 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 except the 5.30% Series Class A Preferred
Stock
Southern Company Services, Inc.
Stockholder Services
P.O. Box 54250
Atlanta, GA 30308-0250
(800) 554-7626
Auditors
Deloitte & Touche LLP
417 North 20th Street
Suite 1000
Birmingham, AL 35203
Legal Counsel
Balch & Bingham LLP
P.O. Box 306
Birmingham, AL 35201
65