EXHIBIT 99
MANAGEMENT'S REPORT
Alabama Power Company 2001 Annual Report
The management of Alabama Power Company has prepared -- and is responsible for
- -- the financial statements and related information included in this report.
These statements were prepared in accordance with accounting principles
generally accepted in the United States and necessarily include amounts that are
based on the best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of four independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Alabama Power Company in conformity with accounting principles generally
accepted in the United States.
/s/Charles D. McCrary
Charles D. McCrary
President
and Chief Executive Officer
/s/William B. Hutchins, III
William B. Hutchins, III
Executive Vice President,
Chief Financial Officer, and Treasurer
February 13, 2002
1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary
of Southern Company) as of December 31, 2001 and 2000, and the related
statements of income, common stockholder's equity, and cash flows for each of
the three years in the period ended December 31, 2001. 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 auditing standards generally
accepted in the 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. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes 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, the financial statements (pages 13-31) referred to above
present fairly, in all material respects, the financial position of Alabama
Power Company as of December 31, 2001 and 2000, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Alabama Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 13, 2002
2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 2001 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 2001 net income after dividends on preferred stock was
$387 million, representing a $33 million (7.9 percent) decrease from the prior
year. This decline is primarily attributable to a decrease in territorial energy
sales as a result of an economic downturn and milder temperatures.
In 2000 earnings were $420 million, representing a 5 percent increase from
the prior year. This improvement was primarily attributable to an increase in
territorial sales partially offset by increased non-fuel operating expenses.
The return on average common equity for 2001 was 11.89 percent compared to
13.58 percent in 2000 and 13.85 percent in 1999.
Revenues
Operating revenues for 2001 were $3.6 billion, reflecting a decrease from 2000.
The following table summarizes the principal factors that have affected
operating revenues for the past two years:
Increase (Decrease)
Amount From Prior Year
--------------------------------------
2001 2001 2000
- -----------------------------------------------------------------
(in thousands)
Retail --
Base revenues $2,033,814 $ (75,125) $ 80,264
Fuel cost recovery
and other 713,859 (129,909) 61,326
- -----------------------------------------------------------------
Total retail 2,747,673 (205,034) 141,590
- -----------------------------------------------------------------
Sales for resale --
Non-affiliates 485,974 24,244 46,353
Affiliates 245,189 78,970 73,780
- -----------------------------------------------------------------
Total sales for resale 731,163 103,214 120,133
Other operating
revenues 107,554 20,749 20,264
- -----------------------------------------------------------------
Total operating
revenues $3,586,390 $ (81,071) $281,987
=================================================================
Percent change (2.21)% 8.33%
- -----------------------------------------------------------------
Retail revenues of $2.7 billion in 2001 decreased
$205 million (6.9 percent) from the prior year, compared with an increase of
$142 million (5 percent) in 2000. The primary contributors to the decrease in
revenues in 2001 were the negative impact of milder temperatures on energy
sales, an economic downturn in the Company's service territory, and a decrease
in fuel revenues. Fuel revenues have no effect on net income because they
represent the recording of revenues to offset fuel expenses. Fuel rates billed
to customers are designed to fully recover fluctuating fuel costs over a period
of time. Lower natural gas prices, an increased fuel rate, and increased hydro
production combined with decreased costs of purchased power have resulted in a
$154 million (65 percent) reduction in under-recovered fuel costs at December
31, 2001 compared with the prior year. The Company expects to continue to reduce
the balance of $83 million during 2002.
3
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
Other operating revenues in 2001 increased $21 million (23.9 percent) over
2000. This increase is primarily attributed to increased steam sales in
conjunction with the operation of the Company's co-generation facilities, fuel
sales, and rent from electric property. Since co-generation steam revenues are
generally offset by fuel expenses, these revenues did not have a significant
impact on earnings.
The $20 million (30.5 percent) increase in other operating revenues in 2000
as compared to 1999 was due primarily to an increase in steam sales in
conjunction with the operation of the Company's co-generation facilities.
Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy energy and
energy sold under short-term contracts are also sold for resale outside the
service area. Revenues from long-term power contracts have both a capacity and
energy component. Capacity revenues reflect the recovery of fixed costs and a
return on investment under the contracts. Energy is generally sold at variable
cost. These capacity and energy components of the unit power contracts were as
follows:
2001 2000 1999
-------------------------------------------
(in millions)
Capacity $125 $127 $122
Energy 134 128 112
------------------------------------------------------------
Total $259 $255 $234
============================================================
Capacity revenues from non-affiliates were relatively unchanged in 2001
compared to the prior two years. There are no scheduled declines in capacity
until the termination of the contracts in 2010.
Revenues from sales to affiliated companies within the Southern electric
system, as well as purchases of energy, will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These transactions did not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:
KWH Percent Change
----------------------------------------
2001 2001 2000
----------------------------------------
(millions)
Residential 15,881 (5.3)% 6.8%
Commercial 12,799 (1.5) 5.5
Industrial 20,460 (7.4) 0.7
Other 198 (3.9) 2.3
------------
Total retail 49,338 (5.2) 3.8
Sales for resale -
Non-affiliates 15,278 2.9 19.4
Affiliates 8,843 64.7 6.7
------------
Total 73,459 1.6 6.9
- -----------------------------------------------------------------
Retail energy sales in 2001 decreased by 5.2 percent due to milder
temperatures and an economic downturn in the Company's service area. This was
offset by an increase in sales for resale to affiliates. Increased operation of
the Company's combined cycle facilities due to lower natural gas prices and an
increase in the Company's combined cycle capacity contributed to the increase in
sales for resale.
The increase in 2000 retail energy sales was primarily due to the strength
of business and economic conditions in the Company's service area. Residential
energy sales experienced a 6.8 percent increase over the prior year primarily as
a result of warmer summer temperatures and cold winter weather conditions
compared to 1999.
Expenses
In 2001 total operating expenses of $2.7 billion were down $50 million or 1.8
percent compared with 2000. This decline is mainly due to an $18 million net
decrease in fuel and purchased power costs and a $56 million decrease in
non-production operation and maintenance expenses, offset by a $19 million
increase in depreciation. Fuel expenses, including purchased power, are offset
by fuel revenues and have no effect on net income.
In 2000 total operating expenses of $2.7 billion were up $235 million or 9.4
percent compared with the prior year. This increase was mainly due to a $183
million increase in fuel and purchased power costs, accompanied by a $23 million
increase in maintenance expenses.
4
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net KWH generated were as follows:
--------------------------
2001 2000 1999
--------------------------
Total generation
(billions of KWHs) 68 65 63
Sources of generation
(percent) --
Coal 64 72 72
Nuclear 18 19 20
Hydro 6 3 5
Oil & Gas 12 6 3
Average cost of fuel per net
KWH generated
(cents) -- 1.56 1.54 1.44
==============================================================
In 2001, total fuel and purchased power costs of $1.3 billion decreased $18
million (1.4 percent), while total energy sales increased 1,174 million kilowatt
hours (1.6 percent) compared with the amounts recorded in 2000. Fuel and
purchased power costs in 2000 increased $183 million (16 percent) compared to
1999.
Purchased power consists of purchases from affiliates in the Southern
electric system and non-affiliated companies. Purchased power transactions among
the Company and its affiliates will vary from period to period depending on
demand, the availability, and the variable production cost of generating
resources at each company. During 2001 purchased power transactions from
non-affiliates decreased $20 million (12 percent) due to the addition in May
2001 of a combined cycle unit and an 82 percent increase in hydro generation
compared to the previous year. The hydro generation increase occurred from
greater stream flows in 2001 compared to the previous year.
The 6 percent decrease in other operation expense in 2001 as compared to
2000 is primarily due to a decrease in administrative and general expenses,
which can be mainly attributed to insurance refunds.
The 8.5 percent decrease in maintenance expense in 2001 as compared to 2000
is primarily due to a decrease in power production expense as a result of timing
of maintenance for steam power generation facilities. The 8.4 percent increase
in maintenance expense in 2000 as compared to 1999 is primarily attributable to
an increase in the maintenance of overhead distribution lines and additional
accruals to partially replenish the natural disaster reserve.
Depreciation and amortization expense increased 5.2 percent in 2001 and 4.9
percent in 2000. These increases reflect additions to property, plant, and
equipment.
Total net interest and other charges increased $10 million (4.0 percent)
in 2001. The increase reflected a decrease in Allowance for Funds Used During
Construction (AFUDC) resulting in a smaller credit to interest expense than was
recorded in 2000. Total net interest and other charges increased $19 million
(7.9 percent) in 2000 primarily from an increase in interest on long-term debt
offset by an increase in AFUDC, which resulted in a larger credit to interest
expense.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
General
The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of future
earnings depends on numerous factors. The major factor is the ability of the
Company to achieve energy sales growth while containing cost in a more
competitive environment. Growth in energy sales is subject to a number of
factors. These factors include weather, competition, new short- and long-term
5
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
contracts with neighboring utilities, energy conservation practiced by
customers, the elasticity of demand, and the rate of economic growth in the
Company's service area.
Assuming normal weather, sales to retail customers are projected to grow
approximately 2.4 percent annually on average during 2002 through 2006.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
state of Alabama. Prices for electricity provided by the Company to retail
customers are set by the Alabama Public Service Commission (APSC) under
cost-based regulatory principles.
Rates to retail customers served by the Company are regulated by the APSC.
Rates for the Company can be adjusted periodically within certain limitations
based on earned retail rate of return compared with an allowed return. The rates
also provide for adjustments to recognize the placing of new generating
facilities into retail service under Rate CNP (Certificated New Plant).
Effective July 2001, the Company's retail rates were adjusted by 0.6 percent
under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into
commercial operation on May 1, 2001. Most recently, a 2 percent increase in
retail rates was effective in October 2001, in accordance with the Rate
Stabilization Equalization plan. See Note 3 to the financial statements under
"Retail Rate Adjustment Procedures" for additional information.
In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items-- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues.
In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000 the APSC certified a seven-year
purchased power agreement pertaining to 615 megawatts of the wholesale
generating facilities, which were sold to Southern Power in June 2001 and are
under construction in Autaugaville, Alabama. All of the 615 megawatts will be
delivered beginning in 2003. In addition the APSC certified a seven-year
purchased power agreement with a third party for approximately 630 megawatts;
one half of the power will be delivered beginning in 2003 while the remaining
half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail
rates when the contracted capacity delivery begins.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash income of
approximately $57 million in 2001. Future pension income is dependent on several
factors including trust earnings and changes to the plan. For the Company,
pension income is a component of the regulated rates and does not have a
significant effect on net income. For more information see Note 2 to the
financial statements.
The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. The Clean Air Act and other important environmental items are
discussed later under "Environmental Matters."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve
as a result of regulatory and competitive factors. Among the primary agents of
change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act
allows independent power producers (IPPs) to access a utility's transmission
network in order to sell electricity to other utilities. This enhances the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and/or commercial customers and sell excess energy generation to other
utilities. Also, electricity sales for resale rates are affected by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the recent restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things
these initiatives allow customers to choose their electricity provider. Some
states have approved initiatives that result in a separation of the ownership
and/or operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While various restructuring and
6
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
competition initiatives have been discussed in Alabama, none have been enacted.
In October 2000 the APSC completed a two-year study of electric industry
restructuring, concluding that (i) restructuring of the electric utility
industry in Alabama was not in the public interest and (ii) the APSC itself
would not mandate retail competition or electric industry restructuring without
enabling state legislation. Electric utility restructuring would require
numerous issues to be resolved, including significant ones relating to recovery
of any stranded investments, full cost recovery of energy produced, and other
issues related to the energy crisis that occurred in California. As a result of
that crisis, many states have either discontinued or delayed implementation of
initiatives involving retail deregulation.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the Company does not remain a low-cost producer and provide
quality service, then energy sales growth could be limited, and this could
significantly erode earnings.
The Company had 1,230 megawatts of wholesale generating facilities under
construction in 2001 at Autaugaville, Alabama. In June 2001 the Company sold
this project to Southern Power Company, a new Southern Company subsidiary formed
in 2001 to construct, own, and manage wholesale generating assets in the
Southeast. The Company has entered into a purchased power agreement with
Southern Power, through May 2010, for half of the capacity of these generating
facilities.
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final ruling on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company and its operating companies, including the Company, have
submitted a series of status reports informing the FERC of progress toward the
development of a Southeastern RTO. In these status reports, Southern Company
explained that it is developing a for-profit RTO known as SeTrans with a number
of non-jurisdictional cooperative and public power entities. Recently, Entergy
Corporation and Cleco Power joined the SeTrans development process. In January
2002 the sponsors of SeTrans held a public meeting to form a Stakeholder
Advisory Committee, which will participate in the development of the RTO.
Southern Company continues to work with the other sponsors to develop the
SeTrans RTO. The creation of SeTrans is not expected to have a material impact
on the Company's financial statements. The outcome of this matter cannot now be
determined.
Accounting Standards
Critical Policy
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operation is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change - effective April 1,
2002 - in accounting for certain contracts related to fuel supplies that contain
quantity options. These contracts will be accounted for as derivatives and
marked to market. However, due to the existence of the Company's cost-based fuel
recovery clause, this change is not expected to have a material impact on net
income.
In June 2001 the FASB issued Statement No. 142, Goodwill and Other Intangible
Assets, which establishes new accounting and reporting standards for acquired
goodwill and other intangible assets and supersedes Accounting Principles Board
Opinion No. 17. Statement No. 142 addresses how intangible assets that are
7
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
acquired individually or with a group of other assets (but not those acquired in
a business combination) should be accounted for upon acquisition and on an
ongoing basis. Goodwill and intangible assets that have indefinite useful lives
will not be amortized but rather will be tested at least annually for
impairment. Intangible assets that have finite useful lives will continue to be
amortized over their useful lives, which are no longer limited to 40 years. The
Company adopted Statement No.142 in January 2002 with no material impact on the
financial statements.
Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.
FINANCIAL CONDITION
Overview
In 2001, despite significant cost control measures, the Company's earnings were
adversely impacted by an economic downturn and milder temperatures. However,
over the last several years the Company's financial condition has remained
stable as a result of growth in retail energy sales and cost control measures
combined with significant lowering of the cost of capital, achieved through the
refinancing and/or redemption of higher-cost long-term debt and preferred stock.
The Company had gross property additions of $636 million in 2001. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.
Exposure to Market Risk
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market. Realized gains and losses
are recognized in the income statement as incurred. At December 31, 2001,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Fair value of changes in energy
trading contracts and year-end valuations are as follows:
Changes
During the Year
------------------
Fair Value
- ---------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 567
Contracts realized or settled (509)
New contracts at inception -
Changes in valuation techniques -
Current period changes 156
- ---------------------------------------------------------------
Contracts end of year $ 214
===============================================================
Source of Year-End
Valuation Prices
------------------------------------
Maturity
Total ----------------------
Fair Value Year 1 1-3 Years
- ------------------------------------------------------------------
(in thousands)
- ------------------------------------------------------------------
Actively quoted $(4,840) $(4,801) $(39)
External sources 5,054 5,054 -
Models and other
methods - - -
- ------------------------------------------------------------------
Contracts end of Year $ 214 $ 253 $(39)
==================================================================
Also, based on the Company's overall variable rate long-term debt exposure
at December 31, 2001, a near-term 100 basis point change in interest rates would
not materially affect the financial statements.
For additional information, see Note 1 to the financial statements under
"Financial Instruments."
In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent 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.
Capital Structure
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.8 percent in 2001, 42.2 percent in 2000, and 42.4
percent in 1999.
In August 2001, the Company issued $442 million of senior notes, the
proceeds of which were used to redeem the $131.5 million outstanding principal
of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other
corporate purposes, including the repayment of a portion of its short-term
indebtedness.
Capital Requirements
Capital expenditures are estimated to be $671 million for 2002, $592 million for
2003, and $673 million for 2004. See Note 4 to the financial statements for
additional details.
Actual construction costs may vary from estimates because of changes in such
factors as: business conditions; environmental regulations; nuclear plant
regulations; load projections; 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.
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $1.1 billion will be required by the end of 2004 for present
sinking fund requirements and maturities of long-term debt. The Company plans to
continue, when economically feasible, to retire higher cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
These capital requirements, lease obligations, and purchase commitments -
discussed in notes 4 and 8 to the financial statements - are as follows:
2002 2003 2004
- -----------------------------------------------------------------
(in millions)
Bonds -
First mortgage $ 4.5 $ - $ -
Pollution control - - -
Senior Notes - 573.2 525.0
Leases -
Capital 0.9 0.9 1.0
Operating 27.9 26.5 25.5
Purchase commitments -
Fuel 795.0 794.0 801.0
Purchased Power - 53.0 83.0
- -----------------------------------------------------------------
At the beginning of 2002, the Company had not used any of its available
credit arrangements. Credit arrangements are as follows:
Expires
----------------------------------
Total Unused 2002 2003 & Beyond
- -----------------------------------------------------------------
(in millions)
$964 $964 $574 $390
- -----------------------------------------------------------------
Environmental Matters
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company. Reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
were required in two phases. Phase I compliance began in 1995.
Southern Company achieved Phase I compliance at its affected plants by
primarily switching to low-sulfur coal and with some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $25 million for the Company.
Phase II sulfur dioxide compliance was required in 2000. The Company used
emission allowances and fuel switching to comply with Phase II requirements.
Also, equipment to control nitrogen oxide emissions was installed on additional
system fossil-fired units as necessary to meet Phase II limits. Compliance with
Phase II increased the Company's total construction expenditures through 2000 by
$63 million.
9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
In December 2000, the Alabama Department of Environmental Management adopted
revisions to the State Implementation Plan for meeting the one-hour ozone
standard. New emission limits to comply with these requirements must be
implemented in May 2003. Two generating plants will be affected in the
Birmingham area. Capital expenditures for compliance with these new rules are
currently estimated at approximately $240 million, of which $170 million remains
to be spent.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
made the standards significantly more stringent. In the subsequent litigation of
these standards, the U. S. Supreme Court found the EPA's implementation program
for the new ozone standard unlawful and remanded it to the EPA. In addition, the
Federal District of Columbia Circuit Court of Appeals is considering other legal
challenges to these standards. A court decision is expected in the spring of
2002. If the standards are eventually upheld, implementation could be required
by 2007 to 2010.
In September 1998, the EPA issued nitrogen oxide reduction rules to the
states for implementation. The final rule affects 21 states, including Alabama.
Compliance is required by May 31, 2004 for most states including Alabama.
Capital expenditures for compliance with these new rules are currently estimated
at approximately $175 million.
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
On November 3, 1999, the EPA brought a civil action against the Company in
the U.S. District Court in Atlanta, Georgia. The complaint alleges violations of
the New Source Review provisions of the Clean Air Act with respect to coal-fired
generating facilities at the Company's Plants Miller, Barry, and Gorgas. The
civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The EPA concurrently issued to the Company a notice of violation
relating to these specific facilities, as well as Plants Greene County and
Gaston. In early 2000 the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation. The complaint and notice of
violation are similar to those brought against and issued to several other
electric utilities. The complaint and notice of violation allege that the
Company had failed to secure necessary permits or install additional pollution
control equipment when performing maintenance and construction at coal burning
plants constructed or under construction prior to 1978. In August 2000, the U.S.
District Court in Georgia granted the Company's motion to dismiss for lack of
jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims
against the Company in federal district court in Birmingham, Alabama. The case
has been stayed since the spring of 2001, pending a ruling by the U.S. Court of
Appeals for the Eleventh Circuit in the appeal of a very similar New Source
Review enforcement action against the Tennessee Valley Authority (TVA). The TVA
case involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on the Company, it is party to that case as well. The U.S. District Court
in Alabama has indicated that it will revisit the issue of a continued stay in
April 2002.
The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. However, an adverse outcome in this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. The Clean Air Act authorizes civil penalties
of up to $27,500 per day per violation at each generating unit. Prior to January
30, 1997, the penalty was $25,000 per day. This could affect future results of
operations, cash flows, and possibly financial condition unless such costs can
be recovered through regulated rates.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury, and perhaps other HAPS is warranted. The program is
being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and the regulations are scheduled to be finalized by the end
of 2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional
10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. 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
will recognize in the financial statements costs to clean up known sites. The
Company has not incurred any significant cleanup costs to date.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These 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; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, and other environmental and health concerns could significantly affect
the Company. The impact of new legislation -- if any -- will depend on the
subsequent development and implementation of applicable regulations.
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 internal sources. However, the type and timing of any financings - if
needed - will depend on market conditions and regulatory approval. In recent
years financings primarily have utilized unsecured debt and trust preferred
securities.
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 Southern Company operating companies.
At December 31, 2001, the Company had outstanding $10 million of commercial
paper.
As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the Company has established external trust funds for nuclear decommissioning
costs. In 1994 the Company also established an external trust fund for
postretirement benefits as ordered by the APSC. The cumulative effect of funding
these items over a long period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
Cautionary Statement Regarding Forward-Looking
Information
This Annual Report includes forward-looking statements in addition to historical
information. Forward-looking information includes, among other things,
statements concerning projected retail sales growth and scheduled completion of
new generation. In some cases forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
"anticipates," "believes," "estimates," "predicts," "projects," "potential,"
"continue," or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in 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 and
also changes in environmental 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, including the pending EPA civil
action against the Company; the impact of fluctuations in commodity prices,
interest rates, and customer demand; state and federal rate regulations;
political, legal, and economic conditions and developments in the United States;
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 effects of and changes in economic conditions in the areas in which
the Company operates; the direct or indirect effects on the Company's business
resulting from the terrorist incidents on September 11, 2001, or any similar
such incidents or responses to such incidents; financial market conditions and
the results of financing efforts; the timing and acceptance of the Company's new
product and service offerings; the ability of the Company to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports (including
Form 10-K) filed from time to time by the Company with the Securities and
Exchange Commission.
12
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $2,747,673 $2,952,707 $2,811,117
Sales for resale --
Non-affiliates 485,974 461,730 415,377
Affiliates 245,189 166,219 92,439
Other revenues 107,554 86,805 66,541
- ---------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,586,390 3,667,461 3,385,474
- ---------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 1,000,828 963,275 855,632
Purchased power --
Non-affiliates 144,991 164,881 93,204
Affiliates 147,967 184,014 180,563
Other 508,264 538,529 531,696
Maintenance 275,510 301,046 277,724
Depreciation and amortization 383,473 364,618 347,574
Taxes other than income taxes 214,665 209,673 204,645
- ---------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,675,698 2,726,036 2,491,038
- ---------------------------------------------------------------------------------------------------------------------
Operating Income 910,692 941,425 894,436
Other Income (Expense):
Interest income, net 15,101 16,152 15,671
Equity in earnings of unconsolidated subsidiaries (Note 5) 4,494 3,156 2,650
Other, net (8,579) (2,226) (12,805)
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 921,708 958,507 899,952
- ---------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 246,436 235,331 217,066
Distributions on preferred securities of subsidiary (Note 8) 24,775 25,549 24,662
- ---------------------------------------------------------------------------------------------------------------------
Total interest and other, net 271,211 260,880 241,728
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 650,497 697,627 658,224
Income taxes (Note 7) 248,597 261,555 241,880
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 401,900 436,072 416,344
Accounting Change
Cumulative effect of accounting change
less income taxes of $215 thousand 353 - -
- ---------------------------------------------------------------------------------------------------------------------
Net Income 402,253 436,072 416,344
Dividends on Preferred Stock 15,524 16,156 16,464
- ---------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 386,729 $ 419,916 $ 399,880
=====================================================================================================================
The accompanying notes are an integral part of these statements.
13
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 402,253 $ 436,072 $ 416,344
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 437,490 412,998 403,332
Deferred income taxes and investment tax credits, net (21,569) 66,166 29,039
Other, net (122,651) (37,703) (12,661)
Changes in certain current assets and liabilities --
Receivables, net 88,325 (125,652) 33,509
Fossil fuel stock (38,663) 23,967 (1,344)
Materials and supplies (13,025) (10,662) (17,968)
Accounts payable (83,077) 107,702 (38,556)
Energy cost recovery, retail 154,320 (69,190) (97,869)
Other 34,503 23,336 5,930
- ----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 837,906 827,034 719,756
- ----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (635,540) (870,581) (809,044)
Sales of property 102,068 - -
Other (34,771) (49,414) (72,218)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (568,243) (919,995) (881,262)
- ----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (271,347) 184,519 96,824
Proceeds --
Common stock 15,642 - -
Other long-term debt 477,000 250,000 751,650
Preferred securities - - 50,000
Capital contributions from parent company 107,313 204,371 204,347
Redemptions --
First mortgage bonds (138,991) (111,009) (470,000)
Other long-term debt (19,021) (5,987) (104,836)
Preferred stock - - (50,000)
Payment of preferred stock dividends (14,942) (16,110) (15,788)
Payment of common stock dividends (393,900) (417,100) (399,600)
Other (9,908) (951) (15,864)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (248,154) 87,733 46,733
- ----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 21,509 (5,228) (114,773)
Cash and Cash Equivalents at Beginning of Period 14,247 19,475 134,248
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 35,756 $ 14,247 $ 19,475
============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $246,316 $237,066 $229,305
Income taxes (net of refunds) 223,961 175,303 170,121
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
14
BALANCE SHEETS
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 35,756 $ 14,247
Receivables --
Customer accounts receivable 281,985 337,870
Under-recovered retail fuel clause revenue 83,497 237,817
Other accounts and notes receivable 49,940 60,315
Affiliated companies 72,639 95,704
Accumulated provision for uncollectible accounts (5,237) (6,237)
Refundable income taxes - -
Fossil fuel stock, at average cost 99,278 60,615
Materials and supplies, at average cost 191,324 178,299
Other 74,640 52,624
- -------------------------------------------------------------------------------------------------------------------
Total current assets 883,822 1,031,254
- -------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 13,159,560 12,431,575
Less accumulated provision for depreciation 5,309,557 5,107,822
- -------------------------------------------------------------------------------------------------------------------
7,850,003 7,323,753
Nuclear fuel, at amortized cost 88,777 94,050
Construction work in progress 357,906 744,974
- -------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 8,296,686 8,162,777
- -------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 5) 44,742 38,623
Nuclear decommissioning trusts 317,508 313,895
Other 12,244 13,612
- -------------------------------------------------------------------------------------------------------------------
Total other property and investments 374,494 366,130
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 7) 334,830 345,550
Prepaid pension costs 314,100 255,256
Debt expense, being amortized 8,150 8,758
Premium on reacquired debt, being amortized 77,173 76,020
Department of Energy assessments 21,015 24,588
Other 108,031 95,772
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 863,299 805,944
- -------------------------------------------------------------------------------------------------------------------
Total Assets $10,418,301 $10,366,105
===================================================================================================================
The accompanying notes are an integral part of these balance sheets.
15
BALANCE SHEETS
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 8) $ 5,382 $ 844
Notes payable 9,996 281,343
Accounts payable --
Affiliated 98,268 124,534
Other 151,705 209,205
Customer deposits 42,124 36,814
Taxes accrued --
Income taxes 113,003 65,505
Other 19,023 19,471
Interest accrued 35,522 33,186
Vacation pay accrued 32,324 31,711
Other 93,589 97,743
- --------------------------------------------------------------------------------------------------------------------------
Total current liabilities 600,936 900,356
- --------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,742,346 3,425,527
- --------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 1,387,661 1,401,424
Deferred credits related to income taxes (Note 7) 202,881 222,485
Accumulated deferred investment tax credits 238,225 249,280
Employee benefits provisions 99,919 71,813
Prepaid capacity revenues (Note 6) 40,730 58,377
Other 130,214 176,559
- --------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,099,630 2,179,938
- --------------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) (Note 8) 347,000 347,000
- --------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 317,512 317,512
- --------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 3,310,877 3,195,772
- --------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $10,418,301 $10,366,105
==========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
16
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
2023 through 2024 7.30% - 7.75% $350,000 $488,991
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 350,000 488,991
- ----------------------------------------------------------------------------------------------------------------------------------
Senior notes --
Variable rate (2.28% at 1/1/02)
due March 3, 2003 167,000 -
5.35% due November 15, 2003 156,200 156,200
7.850% due May 15, 2003 250,000 250,000
7.125% due August 15, 2004 250,000 250,000
4.875% due September 1, 2004 275,000 -
5.49% due November 1, 2005 225,000 225,000
7.125% due October 1, 2007 200,000 200,000
5.375% due October 1, 2008 160,000 160,000
6.25% to 7.125% due 2010-2048 1,199,402 1,202,581
- ----------------------------------------------------------------------------------------------------------------------------------
Total senior notes 2,882,602 2,443,781
- ----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% due 2024 24,400 24,400
Variable rates (1.61% to 1.95% at 1/1/02)
due 2015-2017 89,800 89,800
Non-collateralized:
6.69% due 2021 50,000 65,000
Variable rates (1.75% to 2.05% at 1/1/02)
due 2021-2031 395,940 360,940
- ----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt (Note 8) 560,140 540,140
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 3,323 4,165
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (48,337) (50,706)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $217.2 million) 3,747,728 3,426,371
Less amount due within one year 5,382 844
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $3,742,346 $3,425,527 48.5% 46.9%
- ----------------------------------------------------------------------------------------------------------------------------------
17
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities: (Note 8)
$25 liquidation value --
7.375% $ 97,000 $ 97,000
7.60% 200,000 200,000
Auction rate (3.60% at 1/1/02) 50,000 50,000
- --------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $24.2 million) 347,000 347,000 4.5 4.8
- --------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par or stated value --
4.20% to 4.92% 47,512 47,512
$25 par or stated value --
5.20% to 5.83% 200,000 200,000
Auction rates -- at 1/1/02
3.10% to 3.557% 70,000 70,000
- --------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $15.2 million) 317,512 317,512 4.1 4.4
- --------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 6,000,000 shares
Outstanding - 6,000,000 shares in 2001
and 5,608,955 shares in 2000
Par value 240,000 224,358
Paid-in capital 1,850,676 1,743,363
Premium on Preferred Stock 99 99
Retained earnings 1,220,102 1,227,952
- --------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 3,310,877 3,195,772 42.9 43.9
- --------------------------------------------------------------------------------------------------------------------------
Total Capitalization $7,717,735 $7,285,811 100.0% 100.0%
==========================================================================================================================
The accompanying notes are an integral part of these statements.
18
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1999 $224,358 $1,334,645 $99 $1,224,965 $2,784,067
Net income after dividends on preferred stock - - - 399,880 399,880
Capital contributions from parent company - 204,347 - - 204,347
Cash dividends on common stock - - - (399,600) (399,600)
Other - - - 169 169
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 224,358 1,538,992 99 1,225,414 2,988,863
Net income after dividends on preferred stock - - - 419,916 419,916
Capital contributions from parent company - 204,371 - - 204,371
Cash dividends on common stock - - - (417,100) (417,100)
Other - - - (278) (278)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 224,358 1,743,363 99 1,227,952 3,195,772
Net income after dividends on preferred stock - - - 386,729 386,729
Capital contributions from parent company - 107,313 - - 107,313
Cash dividends on common stock - - - (393,900) (393,900)
Issuance of common stock 15,642 - - - 15,642
Other - - - (679) (679)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $240,000 $1,850,676 $99 $1,220,102 $3,310,877
=============================================================================================================================
The accompanying notes are an integral part of these statements.
19
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2001 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 five operating companies, a system
service company, Southern Communications Services (Southern LINC), Southern
Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern
Power), and other direct and indirect subsidiaries. The operating companies --
Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi
Power Company, and Savannah Electric and Power Company -- provide electric
service in four southeastern states. Contracts among the operating companies -
related to jointly-owned generating facilities, interconnecting transmission
lines, and the exchange of electric power -- are regulated by the Federal Energy
Regulatory Commission (FERC) and/or the Securities and Exchange Commission
(SEC). The system service company provides, at cost, specialized services to
Southern Company and its subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Power was
established in 2001 to construct, own, and manage Southern Company's competitive
generation assets and sell electricity at market-based rates in the wholesale
market.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The Company follows accounting principles generally accepted in the
United States and complies with the accounting policies and practices prescribed
by its respective 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.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Affiliate Transactions
The Company has an agreement with the system service company under which the
following services are rendered to the Company at cost: general and design
engineering, purchasing, accounting and statistical, finance and treasury, tax,
information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures, and other services with
respect to business and operations and power pool transactions. Costs for these
services amounted to $183 million, $187 million, and $218 million during 2001,
2000, and 1999, respectively.
The Company also has an agreement with Southern Nuclear to operate Plant
Farley and provide the following nuclear-related services at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting,
statistical, and employee relations; and other services with respect to business
and operations. Costs for these services amounted to $160 million, $148 million,
and $135 million during 2001, 2000, and 1999, respectively.
In 2001, the Company had under construction a 1,230 megawatt combined cycle
facility in Autaugaville, Alabama. In June 2001, the Company sold this project
to Southern Power Company, a new Southern Company affiliate formed in 2001 to
construct, own, and manage wholesale generating assets in the Southeast.
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. 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.
20
NOTES (continued)
Alabama Power Company 2001 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:
2001 2000
-----------------------
(in millions)
Deferred income tax charges $ 335 $ 346
Deferred income tax credits (203) (222)
Premium on reacquired debt 77 76
Department of Energy assessments 21 25
Vacation pay 32 32
Natural disaster reserve (12) (18)
Other, net 57 30
- ----------------------------------------------------------------
Total $ 307 $ 269
================================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of FASB Statement No. 71, the Company would be required to
write off 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 exists, including plant, and
write down the assets, if impaired, to their fair values.
Revenues and Fuel Costs
The Company currently 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.
Revenues are recognized as services are rendered. Unbilled revenues are accrued
at the end of each fiscal period. Fuel revenues have no effect on net income
because they represent the recording of revenues to offset fuel expenses,
including the fuel component of purchased energy. Fuel rates billed to customers
are designed to fully recover fluctuating fuel costs over a period of time.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts continue to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge based on nuclear generation for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $58
million in 2001, $61 million in 2000, and $63 million in 1999.
The Company has a contract with 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 fuel in January 1998 as required by the contract, and
the Company is pursuing legal remedies against the government for breach of
contract. Sufficient fuel storage capacity is available at Plant Farley to
maintain full-core discharge capability until the refueling outage scheduled in
2006 for Farley Unit 1 and the refueling outage scheduled in 2008 for Farley
Unit 2. Procurement of on-site dry spent fuel storage capacity at Plant Farley
is in progress, with the intent to place the capacity in operation as early as
2005.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is funded in part by
a special assessment on utilities with nuclear plants. This assessment is being
paid over a 15-year period, which began in 1993. This fund will be used by the
DOE for the decontamination and decommissioning of its nuclear fuel enrichment
facilities. The law provides that utilities will recover these payments in the
same manner as any other fuel expense. The Company estimates its remaining
liability under this law to be approximately $21 million at December 31, 2001.
This obligation is recognized in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.2 percent in 2001, 2000, and 1999. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to accumulated
provision for depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
Depreciation expense includes an amount for the expected cost of decommissioning
nuclear facilities and removal of other facilities.
The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial nuclear power reactors to establish a plan for providing with
reasonable assurance funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Amounts previously
recorded in internal reserves are being transferred into the external trust
funds over periods approved by the APSC. The NRC's minimum external funding
requirements are based on a generic estimate of the cost to decommission the
radioactive portions of a nuclear unit based on the size and type of reactor.
21
NOTES (continued)
Alabama Power Company 2001 Annual Report
The Company has filed plans with the NRC to ensure that -- over time -- the
deposits and earnings of the external trust funds will provide the minimum
funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the site
study year, and ultimate cost is the estimate to decommission the facility as of
retirement date. The estimated costs of decommissioning -- both site study costs
and ultimate costs - based on the most current study for Plant Farley were as
follows:
Site study basis (year) 1998
Decommissioning periods:
Beginning year 2017
Completion year 2031
------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $629
Non-radiated structures 60
------------------------------------------------------------
Total $689
============================================================
(in millions)
Ultimate costs:
Radiated structures $1,868
Non-radiated structures 178
------------------------------------------------------------
Total $2,046
============================================================
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 estimates.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the APSC. The amount expensed in 2001 and fund balances as of
December 31, 2001 were:
(in millions)
Amount expensed in 2001 $ 18
-------------------------------------------------------------
Accumulated provisions:
External trust funds, at fair value $318
Internal reserves 36
-------------------------------------------------------------
Total $354
=============================================================
All of the Company's decommissioning costs are approved for recovery by the
APSC through the ratemaking process. Significant assumptions include an
estimated inflation rate of 4.5 percent and an estimated trust earnings rate of
7.0 percent. The Company expects the APSC to periodically review and adjust, if
necessary, the amounts collected in rates for the anticipated cost of
decommissioning.
Income 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 lives of the related property.
Allowance For Funds Used During Construction
(AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new 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 amount of AFUDC capitalized was $19 million in 2001,
$43 million in 2000, and $23 million in 1999. The composite rate used to
determine the amount of allowance was 7.7 percent in 2001, 9.6 percent in 2000,
and 8.8 percent in 1999. AFUDC, net of income tax, as a percent of net income
after dividends on preferred stock was 3.3 percent in 2001, 8.4 percent in 2000,
and 4.7 percent in 1999.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. 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 estimated cost of funds used during construction. The cost of
maintenance, repairs and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property--exclusive of minor
items of property--is capitalized.
Financial Instruments
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on
net income was immaterial.
The Company uses derivative financial instruments to hedge exposures to
fluctuations in foreign currency exchange rates and certain commodity prices.
22
NOTES (continued)
Alabama Power Company 2001 Annual Report
Gains and losses on qualifying hedges are deferred and recognized either in
income or as an adjustment to the carrying amount of the hedged item when the
transaction occurs.
The Company and its affiliates, through the system service company acting as
their agent, enters into commodity related forward and option contracts to limit
exposure to changing prices on certain fuel purchases and electricity purchases
and sales. Substantially all of the Company's bulk energy purchases and sales
contracts meet the definition of a derivative under FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities. In many cases
these fuel and electricity contracts qualify for normal purchase and sale
exceptions under Statement No. 133 and are accounted for under the accrual
method. Other contracts qualify as cash flow hedges of anticipated transactions,
resulting in the deferral of related gains and losses and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.
In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent 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.
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.
Other Company financial instruments for which the carrying amount did not
equal fair value at December 31 are as follows:
Carrying Fair
Amount Value
-------------------------
(in millions)
Long-term debt:
At December 31, 2001 $3,744 $3,800
At December 31, 2000 3,422 3,375
Preferred Securities:
At December 31, 2001 347 346
At December 31, 2000 347 344
--------------------------------------------------------------
The fair value for long-term debt and preferred securities was based on
either closing market prices or closing prices of comparable instruments.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Natural Disaster Reserve
In accordance with an APSC order, the Company has established a Natural Disaster
Reserve. The Company is allowed to accrue $250 thousand per month until the
maximum accumulated provision of $32 million is attained. Higher accruals to
restore the reserve to its authorized level are allowed whenever the balance in
the reserve declines below $22.4 million. At December 31, 2001, the reserve
balance was $12 million.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all employees may become
eligible for such benefits when they retire. The Company funds trusts to the
extent deductible under federal income tax regulations or to the extent required
by the APSC and the FERC. In late 2000 the Company adopted several pension and
postretirement benefit plan changes that had the effect of increasing benefits
to both current and future retirees.
23
NOTES (continued)
Alabama Power Company 2001 Annual Report
The measurement date for plan assets and obligations is September 30 of each
year. The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
2001 2000
- -------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Long-term return on plan assets 8.50 8.50
- -------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
------------------------
2001 2000
- ------------------------------------------------------------
(in millions)
Balance at beginning of year $925 $896
Service cost 25 23
Interest cost 70 65
Benefits paid (56) (51)
Actuarial gain and
employee transfers (1) (8)
Amendments 48 -
- ------------------------------------------------------------
Balance at end of year $1,011 $925
============================================================
Plan Assets
------------------------
2001 2000
- ------------------------------------------------------------
(in millions)
Balance at beginning of year $1,921 $1,647
Actual return on plan assets (277) 302
Benefits paid (56) (51)
Employee transfers (4) 23
- ------------------------------------------------- ----------
Balance at end of year $1,584 $1,921
============================================================
The accrued pension costs recognized in the Balance Sheets were as
follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $ 573 $ 996
Unrecognized transition obligation (15) (20)
Unrecognized prior service cost 78 36
Unrecognized net actuarial gain (322) (757)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 314 $ 255
===============================================================
Components of the pension plan's net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 25 $ 23 $ 23
Interest cost 70 65 58
Expected return on plan assets (131) (119) (109)
Recognized net actuarial gain (22) (19) (13)
Net amortization 1 (1) (1)
- ---------------------------------------------------------------
Net pension income $ (57) $ (51) $ (42)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
-------------------------
2001 2000
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $264 $264
Service cost 5 4
Interest cost 24 19
Benefits paid (18) (12)
Actuarial gain and
employee transfers (13) (11)
Amendments 86 -
- -------------------------------------------------------------
Balance at end of year $348 $264
=============================================================
Plan Assets
-------------------------
2001 2000
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $192 $161
Actual return on plan assets (24) 25
Employer contributions 19 18
Benefits paid (18) (12)
- -------------------------------------------------------------
Balance at end of year $169 $192
=============================================================
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $ (179) $ (72)
Unrecognized transition obligation 45 49
Prior service cost 82 -
Unrecognized net actuarial gain (9) (35)
Fourth quarter contributions 8 4
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (53) $ (54)
===============================================================
24
NOTES (continued)
Alabama Power Company 2001 Annual Report
Components of the plans' net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 5 $ 4 $ 5
Interest cost 24 19 18
Expected return on plan assets (15) (13) (11)
Net amortization 7 4 4
- ---------------------------------------------------------------
Net postretirement cost $ 21 $ 14 $ 16
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $30 $26
Service and interest costs 3 2
===============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $12
million, $11 million, and $10 million, respectively.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs totaling $13.0
million, $2.6 million and $5.6 million for the years 2001, 2000 and 1999,
respectively. These costs were deferred and are being amortized in accordance
with regulatory treatment. The unamortized balance of these costs was $11.9
million at December 31, 2001.
3. CONTINGENCIES AND REGULATORY
MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in U.S. District Court in Georgia against the Company. The complaint
alleges violations of the New Source Review provisions of the Clean Air Act with
respect to coal-fired generating facilities at the Company's Plants Miller,
Barry, and Gorgas. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The Clean Air Act authorizes civil penalties
of up to $27,500 per day, per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day.
The EPA concurrently issued to the Company a notice of violation relating to
these specific facilities, as well as Plants Greene County and Gaston. In early
2000, the EPA filed a motion to amend its complaint to add the violations
alleged in its notice of violation. The complaint and the notice of violation
are similar to those brought against and issued to several other electric
utilities. The complaint and the notice of violation allege that the Company
failed to secure necessary permits or install additional pollution control
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. On August 1, 2000, the U.S.
District Court granted the Company's motion to dismiss for lack of jurisdiction
in Georgia. On January 12, 2001, the EPA re-filed its claims against the Company
in federal district court in Birmingham, Alabama.
The Company's case has been stayed since the spring of 2001, pending a ruling
by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very
similar New Source Review enforcement action against the Tennessee Valley
Authority (TVA). The TVA case involves many of the same legal issues raised by
the actions against the Company. Because the outcome of the TVA case could have
25
NOTES (continued)
Alabama Power Company 2001 Annual Report
a significant adverse impact on the Company, it is a party to that case as well.
The U.S. District Court in Alabama has indicated that it will revisit the issue
of a continued stay in April 2002.
The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
Retail Rate Adjustment Procedures
The APSC has adopted rates that provide for periodic adjustments based upon the
Company's earned return on end-of-period retail common equity. The rates also
provide for adjustments to recognize the placing of new generating facilities
into retail service under Rate CNP (Certificated New Plant). Both increases and
decreases have been placed into effect since the adoption of these rates.
Effective July 2001, the Company's retail rates were adjusted by 0.6 percent
under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into
commercial operation on May 1, 2001. Most recently, a 2 percent increase in
retail rates was effective in October 2001 in accordance with the Rate
Stabilization Equalization plan. The rate adjustment procedures allow a return
on common equity range of 13.0 percent to 14.5 percent and limit increases or
decreases in rates to 4 percent in any calendar year.
In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. During the
years 2001, 2000, and 1999, the Company did not record any such reductions.
In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000, the APSC certified a seven-year
purchased power agreement pertaining to 615 megawatts of the wholesale
generating facilities which were sold to Southern Power in June 2001 and are
under construction in Autaugaville, Alabama. All of the 615 megawatts will be
delivered beginning in 2003. In addition the APSC certified a seven-year
purchased power agreement with a third party for approximately 630 megawatts;
one half of the power will be delivered beginning in 2003 while the remaining
half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail
rates when the contracted capacity delivery begins.
In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent 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.
The Company's ratemaking procedures will remain in effect until the APSC
votes to modify or discontinue them.
4. COMMITMENTS
Construction Program
During 2001, the Company completed the replacement of the steam generators
at Plant Farley, as well as the construction of new generating capacity at Plant
Barry. Significant construction will continue related to transmission and
distribution facilities and the upgrading of generating plants, including the
expenditures necessary to comply with environmental regulation.
The Company currently estimates property additions to be $671 million in
2002, $592 million in 2003, and $673 million in 2004.
In connection with the transfer of the Autaugaville construction project,
the Company has assigned $71 million in vendor equipment contracts to Southern
Power. While the Company could be obligated to assume responsibility for these
contracts if Southern Power fails to meet these commitments, Southern Company
has entered into limited keep-well arrangements whereby Southern Company would
contribute funds to Southern Power either through loans or capital contributions
in order to fund performance by Southern Power as equipment purchaser under
certain contingencies. Southern Company has also guaranteed Southern Power
obligations totaling $6.6 million for the Company's construction of transmission
interconnection facilities to the plant.
The capital budget is subject to periodic review and revision, and actual
capital costs incurred may vary from estimates because of changes in such
26
NOTES (continued)
Alabama Power Company 2001 Annual Report
factors as: business conditions; environmental regulations; nuclear plant
regulations; load projections; 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.
Purchased Power Commitments
The Company has entered into various long-term commitments for the purchase of
electricity. Estimated total long-term obligations at December 31, 2001 were as
follows:
Commitments
-----------------------------------
Non-
Year Affiliated Affiliated Total
- ---- ----------------------------------
(in millions)
2002 $ - $ - $ -
2003 37 16 53
2004 49 34 83
2005 49 37 86
2006 49 38 87
2007 and thereafter 160 142 302
- --------------------------------------------------------------
Total commitments $344 $267 $611
==============================================================
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.
Total estimated long-term obligations at December 31, 2001, were as follows:
Year Commitments
- ---- ---------------
(in millions)
2002 $ 795
2003 794
2004 801
2005 571
2006 512
2007 and thereafter 1,020
- ---------------------------------------------------------------
Total commitments $4,493
===============================================================
In addition, the system service company acts as agent for the five operating
companies and Southern Power with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various indices at the actual time of
delivery; therefore, only the volume commitments are firm. The Company's
committed volumes allocated based on usage projections, as of December 31, 2001,
are as follows:
Year Natural Gas
- ---- -----------
(MMBtu)
2002 77,365,361
2003 72,139,927
2004 45,600,417
2005 22,849,132
2006 14,808,334
2007 and thereafter 5,609,190
- ------------------------------------------------------------
Total commitments 238,372,361
============================================================
Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.
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
$27.9 million in 2001, $20.9 million in 2000, and $17.8 million in 1999. At
December 31, 2001, estimated minimum rental commitments for noncancellable
operating leases were as follows:
Year Commitments
- ---- ----------------
(in millions)
2002 $ 27.9
2003 26.5
2004 25.5
2005 21.6
2006 14.4
2007 and thereafter 38.1
- --------------------------------------------------------------
Total minimum payments $ 154.0
==============================================================
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 2004 and 2006, and the Company's
maximum obligations are $25.7 million and $66.0 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 reduce or eliminate the Company's payments under
the residual value obligation.
5. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power own equally all of the outstanding capital stock
of Southern Electric Generating Company (SEGCO), which owns electric generating
units with a total rated capacity of 1,020 megawatts, together with associated
27
NOTES (continued)
Alabama Power Company 2001 Annual Report
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 year's notice. The Company's
share of expenses totaled $80 million in 2001, $85 million in 2000, and $92
million in 1999 and is included in "Purchased power from affiliates" in the
Statements of Income.
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. Georgia
Power has agreed to reimburse the Company for the pro rata portion of such
obligation 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, 2001, the capitalization of SEGCO consisted of $58 million
of equity and $86 million of long-term debt on which the annual interest
requirement is $2.2 million. SEGCO paid dividends totaling $0.7 million in 2001,
$5.1 million in 2000, and $4.3 million in 1999 of which one-half of each was
paid to the Company. SEGCO's net income was $7.5 million, $5.9 million, and $5.4
million for 2001, 2000, and 1999, respectively.
The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 2001, is as follows:
Total
Megawatt Company
Facility (Type) Capacity Ownership
--------------------- ------------ -------------
Greene County 500 60.00% (1)
(coal)
Plant Miller
Units 1 and 2 1,320 91.84% (2)
(coal)
-----------------------------------------------------------
(1) Jointly owned with an affiliate, Mississippi Power Company.
(2) Jointly owned with Alabama Electric Cooperative, Inc.
Company Accumulated
Facility Investment Depreciation
--------------------- -------------- ---------------
(in millions)
Greene County $101 $ 49
Plant Miller
Units 1 and 2 747 326
----------------------------------------------------------
6. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the other operating companies of Southern Company have entered
into long-term contractual agreements for the sale and lease of capacity and
energy to certain non-affiliated utilities located outside the system's service
area. These agreements -- expiring at various dates discussed below -- are firm
and related to specific generating units. Because the energy is generally
provided at cost under these agreements, profitability is primarily affected by
capacity revenues.
Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority
(JEA). Under these agreements approximately 1,237 megawatts of capacity are
scheduled to be sold through 2010. The Company's capacity revenues amounted to
$125 million in 2001, $127 million in 2000, and $122 million in 1999.
Alabama Municipal Electric Authority (AMEA)
Capacity Contracts
In 1986 the Company entered into a firm power sales contract with AMEA entitling
AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for a period
of 15 years (1986 Contract). In October 1991 the Company entered into a second
firm power sales contract with AMEA entitling AMEA to scheduled amounts of
additional capacity (to a maximum 80 megawatts) for a period of 15 years (1991
Contract). Under the terms of the contracts, the Company received payments from
AMEA representing the net present value of the revenues associated with the
respective capacity entitlements, discounted at effective annual rates of 9.96
percent and 11.19 percent for the 1986 and 1991 contracts, respectively. The
1986 contract expired in July 2001, however, the payments for the 1991 contract
will continue to be recognized as operating revenues and the discounts will be
amortized to other interest expense as scheduled capacity is made available over
the terms of the contract.
To secure AMEA's advance payments and the Company's performance obligation
under the contracts, the Company issued and delivered to an escrow agent first
mortgage bonds representing the maximum amount of liquidated damages payable by
the Company in the event of a default under the contracts. No principal or
interest is payable on such bonds unless and until a default by the Company
28
NOTES (continued)
Alabama Power Company 2001 Annual Report
occurs. As the liquidated damages decline, a portion of the bond equal to the
decrease is returned to the Company. At December 31, 2001, $38.1 million of the
1991 bond was held by the escrow agent under the contract.
7. INCOME TAXES
At December 31, 2001, the tax-related regulatory assets and liabilities were
$335 million and $203 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 current enacted tax law and to
unamortized investment tax credits.
Details of the income tax provisions are as follows:
2001 2000 1999
--------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $234 $168 $194
Deferred (20) 60 24
- -----------------------------------------------------------------
214 228 218
- -----------------------------------------------------------------
State --
Current 37 27 19
Deferred (2) 7 5
- -----------------------------------------------------------------
35 34 24
- -----------------------------------------------------------------
Total $249 $262 $242
=================================================================
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:
2001 2000
------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 1,034 $ 992
Property basis differences 390 405
Fuel cost adjustment 28 93
Premium on reacquired debt 29 30
Pensions 89 75
Other 23 12
- -----------------------------------------------------------------
Total 1,593 1,607
- -----------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 13 18
Other deferred costs 14 14
Postretirement benefits 21 24
Unbilled revenue 18 23
Other 93 81
- -----------------------------------------------------------------
Total 159 160
- -----------------------------------------------------------------
Total deferred tax liabilities, net 1,434 1,447
Portion included in current liabilities, net (47) (46)
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,387 $1,401
=================================================================
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 $11 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
2001 2000 1999
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.5 3.1 2.4
Non-deductible book
depreciation 1.5 1.4 1.6
Differences in prior years'
deferred and current tax rates (1.3) (1.3) (1.3)
Other (0.5) (0.7) (0.9)
- ---------------------------------------------------------------
Effective income tax rate 38.2% 37.5% 36.8%
===============================================================
Southern Company files a consolidated federal and certain state income tax
returns. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.
29
NOTES (continued)
Alabama Power Company 2001 Annual Report
8. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:
Date of Maturity
Issue Amount Rate Notes Date
---------------------------------------------------
(millions) (millions)
Trust I 1/1996 $ 97 7.375% $100 3/2026
Trust II 1/1997 200 7.60 206 12/2036
Trust III 2/1999 50 Auction 52 2/2029
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above. The distribution rate of Trust III's auction rate securities was 3.60% at
January 1, 2002.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.
The Trusts are subsidiaries of the Company and accordingly are consolidated
in the Company's financial statements.
Pollution Control Bonds
Pollution control obligations represent installment purchases of pollution
control 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. With
respect to $114.2 million of such pollution control obligations, the Company has
authenticated and delivered to the trustees a like principal amount of first
mortgage bonds as security for its obligations under the installment purchase
agreements. No principal or interest on these first mortgage bonds is payable
unless and until a default occurs on the installment purchase agreements.
In 2001, the Company sold, through a public authority, $20 million of
pollution control bonds, the proceeds of which were used to pay certain costs
incurred in connection with the acquisition, construction, installation, and
equipping of certain local district heating facilities and sewage and solid
waste facilities at two of the Company's generation facilities.
Senior Notes
In August 2001 the Company issued $442 million of unsecured senior notes, the
proceeds of which were used to redeem the $131.5 million outstanding principal
of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other
corporate purposes including the repayment of a portion of its short-term
indebtedness. All of the Company's senior notes are, in effect, subordinate to
all secured debt of the Company, including its first mortgage bonds.
Capitalized Leases
The estimated aggregate annual maturities of capitalized lease obligations
through 2006 are as follows: $0.9 million in 2002, $0.9 million in 2003, $1.0
million in 2004, $0.4 million in 2005, and $0.1 million in 2006.
Securities Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
2001 2000
----------------------
(in thousands)
First mortgage bond maturities
and redemptions $4,498 $ -
Other long-term debt maturities 884 844
------------------------------------------------------------
Total long-term debt due within
one year $5,382 $844
============================================================
The annual first mortgage bond improvement fund requirement is 1 percent of
the aggregate principal amount of bonds of each series authenticated, so long as
a portion of that series is outstanding, and may be satisfied by the deposit of
cash and/or reacquired bonds, the certification of unfunded property additions,
or a combination thereof.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $964 million
(including $454 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$574 million expire at various times during 2002 and $390 million expire in
30
NOTES (continued)
Alabama Power Company 2001 Annual Report
2004. In certain cases, such lines require payment of a commitment fee based on
the unused portion of the commitment or the maintenance of compensating balances
with the banks. Because the arrangements are based on an average balance, the
Company does not consider any of its cash balances to be restricted as of any
specific date. Moreover, the Company borrows from time to time pursuant to
arrangements with banks for uncommitted lines of credit. The amount of
commercial paper outstanding at December 31, 2001 was $10 million.
At December 31, 2001, the Company had regulatory approval to have
outstanding up to $1 billion of short-term borrowings.
Assets Subject to Lien
The Company's mortgage, as amended and supplemented, securing the first mortgage
bonds issued by the Company, constitutes a direct lien on substantially all of
the Company's fixed property and franchises.
Dividend Restrictions
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 2001, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (the 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 $9.5 billion for public liability claims
that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $200 million by American Nuclear Insurers (ANI),
with the remaining coverage provided by a mandatory program of deferred premiums
which could be assessed, after a nuclear incident, against all owners of nuclear
reactors. The Company could be assessed up to $88 million per incident for each
licensed reactor it operates but not more than an aggregate of $10 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
$176 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year.
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 cost 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 between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years.
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
three NEIL policies would be $35 million.
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. However, both companies revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.
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.
31
NOTES (continued)
Alabama Power Company 2001 Annual Report
10. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 2001 and 2000 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- -------------------- -----------------------------------------
(in millions)
March 2001 $ 850 $180 $ 70
June 2001 904 194 75
September 2001 1,061 362 180
December 2001 772 175 62
March 2000 $ 746 $172 $ 68
June 2000 900 229 103
September 2000 1,137 390 209
December 2000 884 151 40
- -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
32
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Alabama Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111
Net Income after Dividends
on Preferred Stock (in thousands) $386,729 $419,916 $399,880 $377,223 $375,939
Cash Dividends
on Common Stock (in thousands) $393,900 $417,100 $399,600 $367,100 $339,600
Return on Average Common Equity (percent) 11.89 13.58 13.85 13.63 13.76
Total Assets (in thousands) $10,418,301 $10,366,105 $9,648,704 $9,225,698 $8,812,867
Gross Property Additions (in thousands) $635,540 $870,581 $809,044 $610,132 $451,167
- ----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,310,877 $3,195,772 $2,988,863 $2,784,067 $2,750,569
Preferred stock 317,512 317,512 317,512 317,512 255,512
Company obligated mandatorily
redeemable preferred securities 347,000 347,000 347,000 297,000 297,000
Long-term debt 3,742,346 3,425,527 3,190,378 2,646,566 2,473,202
- ----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,717,735 $7,285,811 $6,843,753 $6,045,145 $5,776,283
============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 42.9 43.9 43.7 46.1 47.6
Preferred stock 4.1 4.4 4.6 5.3 4.4
Company obligated mandatorily
redeemable preferred securities 4.5 4.8 5.1 4.9 5.2
Long-term debt 48.5 46.9 46.6 43.7 42.8
- ----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
============================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's A A A+ A+ A+
Fitch A+ AA- AA- AA- AA-
Preferred Stock -
Moody's Baa1 a2 a2 a2 a2
Standard and Poor's BBB+ BBB+ A- A A
Fitch A- A A A A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 A2
Standard and Poor's A A A A A
Fitch A A+ A+ A+ A+
============================================================================================================================
Customers (year-end):
Residential 1,139,542 1,132,410 1,120,574 1,106,217 1,092,161
Commercial 196,617 193,106 188,368 182,738 177,362
Industrial 4,728 4,819 4,897 5,020 5,076
Other 751 745 735 733 728
- ----------------------------------------------------------------------------------------------------------------------------
Total 1,341,638 1,331,080 1,314,574 1,294,708 1,275,327
============================================================================================================================
Employees (year-end): 6,706 6,871 6,792 6,631 6,531
- ----------------------------------------------------------------------------------------------------------------------------
33
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Alabama Power Company 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,138,499 $1,222,509 $ 1,145,646 $ 1,133,435 $ 997,507
Commercial 829,760 854,695 807,098 779,169 724,148
Industrial 763,934 859,668 843,090 853,550 775,591
Other 15,480 15,835 15,283 14,523 13,563
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 2,747,673 2,952,707 2,811,117 2,780,677 2,510,809
Sales for resale - non-affiliates 485,974 461,730 415,377 448,973 431,023
Sales for resale - affiliates 245,189 166,219 92,439 103,562 161,795
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,478,836 3,580,656 3,318,933 3,333,212 3,103,627
Other revenues 107,554 86,805 66,541 53,161 45,484
- ------------------------------------------------------------------------------------------------------------------------------
Total $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 15,880,971 16,771,821 15,699,081 15,794,543 14,336,408
Commercial 12,798,711 12,988,728 12,314,085 11,904,509 11,330,312
Industrial 20,460,022 22,101,407 21,942,889 21,585,117 20,727,912
Other 198,102 205,827 201,149 196,647 180,389
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 49,337,806 52,067,783 50,157,204 49,480,816 46,575,021
Sales for resale - non-affiliates 15,277,839 14,847,533 12,437,599 11,840,910 12,329,480
Sales for resale - affiliates 8,843,094 5,369,474 5,031,781 5,976,099 8,993,326
- ------------------------------------------------------------------------------------------------------------------------------
Total 73,458,739 72,284,790 67,626,584 67,297,825 67,897,827
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.17 7.29 7.30 7.18 6.96
Commercial 6.48 6.58 6.55 6.55 6.39
Industrial 3.73 3.89 3.84 3.95 3.74
Total retail 5.57 5.67 5.60 5.62 5.39
Sales for resale 3.03 3.11 2.91 3.10 2.78
Total sales 4.74 4.95 4.91 4.95 4.57
Residential Average Annual
Kilowatt-Hour Use Per Customer 13,981 14,875 14,097 14,370 13,254
Residential Average Annual
Revenue Per Customer $1,002.30 $1,084.26 $1,028.76 $1,031.21 $922.21
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 12,153 12,122 11,379 11,151 11,151
Maximum Peak-Hour Demand (megawatts):
Winter 9,300 9,478 8,863 7,757 8,478
Summer 10,241 11,019 10,739 10,329 9,778
Annual Load Factor (percent) 62.5 59.3 59.7 62.9 62.7
Plant Availability (percent):
Fossil-steam 87.1 89.4 80.4 85.6 86.3
Nuclear 83.7 88.3 91.0 80.2 88.8
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 56.8 63.0 64.1 65.3 65.7
Nuclear 15.8 16.9 17.8 16.3 17.9
Hydro 5.1 2.9 4.7 6.9 7.5
Oil and gas 10.7 4.9 1.1 1.5 0.7
Purchased power -
From non-affiliates 4.4 4.6 4.5 3.3 2.4
From affiliates 7.2 7.7 7.8 6.7 5.8
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
34