SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) February 16, 2000
-----------------------------
ALABAMA POWER COMPANY
- -------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Alabama 1-3164 63-0004250
- -------------------------------------------------------------------------------
(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification No.)
600 North 18th Street, Birmingham, Alabama 35291
- -------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (205) 257-1000
--------------------------
N/A
- -------------------------------------------------------------------------------
(Former name or former address, if changed since last report.)
<PAGE>
Item 7. Financial Statements and Exhibits.
(c) Exhibits.
23 - Consent of Arthur Andersen LLP.
27 - Financial Data Schedule.
99 - Audited Financial Statements of Alabama Power
Company as of December 31, 1999.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ALABAMA POWER COMPANY
By /s/Wayne Boston
Wayne Boston
Assistant Secretary
Date: March 2, 2000
Exhibit 23
Arthur Andersen LLP
Suite 2500
133 Peachtree Street, NE
Atlanta, GA 30303-1816
404-658-1776
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report dated February 16, 2000 on the financial statements of Alabama
Power Company, included in this Form 8-K, into Alabama Power Company's
previously filed Registration Statement File No. 333-67453.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 28, 2000
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
financial statements filed as Exhibit 99 and is qualified in its entirety by
reference to such financial statements.
</LEGEND>
<CIK> 000003153
<NAME> ALABAMA POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> Dec-31-1999
<PERIOD-END> Dec-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7,703,683
<OTHER-PROPERTY-AND-INVEST> 333,700
<TOTAL-CURRENT-ASSETS> 848,332
<TOTAL-DEFERRED-CHARGES> 762,989
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 9,648,704
<COMMON> 224,358
<CAPITAL-SURPLUS-PAID-IN> 1,539,091
<RETAINED-EARNINGS> 1,225,414
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,988,863
347,000
317,512
<LONG-TERM-DEBT-NET> 987,388
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 2,198,822
<COMMERCIAL-PAPER-OBLIGATIONS> 96,824
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0
<CAPITAL-LEASE-OBLIGATIONS> 4,168
<LEASES-CURRENT> 943
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<GROSS-OPERATING-REVENUE> 3,385,474
<INCOME-TAX-EXPENSE> 241,880
<OTHER-OPERATING-EXPENSES> 2,491,038
<TOTAL-OPERATING-EXPENSES> 2,491,038
<OPERATING-INCOME-LOSS> 894,436
<OTHER-INCOME-NET> 33,685
<INCOME-BEFORE-INTEREST-EXPEN> 686,241
<TOTAL-INTEREST-EXPENSE> 269,897
<NET-INCOME> 416,344
16,464
<EARNINGS-AVAILABLE-FOR-COMM> 399,880
<COMMON-STOCK-DIVIDENDS> 399,600
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</TABLE>
MANAGEMENT'S REPORT
Alabama Power Company 1999 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 generally accepted accounting
principles appropriate in the circumstances 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 books and 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 directors who are
not employees, 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 generally accepted accounting
principles.
/s/Elmer B. Harris
Elmer B. Harris
President
and Chief Executive Officer
/s/William B. Hutchins, III
William B. Hutchins, III
Executive Vice President,
Chief Financial Officer, and Treasurer
February 16, 2000
1
<PAGE>
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, 1999 and 1998, 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, 1999. 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 11-29) referred to above
present fairly, in all material respects, the financial position of Alabama
Power Company as of December 31, 1999 and 1998, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 16, 2000
2
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1999 net income after dividends on preferred stock was
$400 million, representing a $23 million (6 percent) increase from the prior
year. This improvement is primarily attributable to a decrease in amortization
related to premiums paid to reacquire debt pursuant to an Alabama Public Service
Commission (APSC) order. See Note 3 to the financial statements under "Retail
Rate Adjustment Procedures" for additional details.
In 1998, earnings were $377 million, representing a 0.3 percent increase
from the prior year. This increase was due to increased retail energy sales as a
result of hot weather in the second quarter of 1998, compared to very mild
weather for the same period in 1997 and a strong economy in the Company's
service territory. However, earnings were offset by an increase in non-fuel
operation and maintenance expenses and an increase in the amortization related
to premiums paid to reacquire debt pursuant to an APSC order.
The return on average common equity for 1999 was 13.85 percent compared to
13.63 percent in 1998, and 13.76 percent in 1997.
Revenues
Operating revenues for 1999 were $3.4 billion, reflecting a slight decrease from
1998. The following table summarizes the principal factors that have affected
operating revenues for the past three years:
Increase (Decrease) From Prior Year
-----------------------------------------
1999 1998 1997
-----------------------------------------
(in thousands)
Retail --
Growth and price
changes $ 27,893 $ 75,642 $ 33,813
Weather (17,871) 55,282 (22,973)
Fuel cost recovery
and other 20,418 138,944 31,353
- ---------------------------------------------------------------------
Total retail 30,440 269,868 42,193
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Sales for resale --
Non affiliates (33,596) 17,950 39,354
Affiliates (11,123) (58,233) (54,825)
- ---------------------------------------------------------------------
Total sales for resale (44,719) (40,283) (15,471)
Other operating
revenues 13,380 7,677 1,614
- ---------------------------------------------------------------------
Total operating
revenues $ (899) $237,262 $ 28,336
=====================================================================
Percent change (0.03)% 7.53% 0.91%
- ---------------------------------------------------------------------
Retail revenues of $2.8 billion in 1999 increased
$30 million (1.1 percent) from the prior year, compared with an increase of $270
million (10.7 percent) in 1998. The primary contributors to the increase in
revenues in 1999 were continued growth in the Company's service territory, as
well as an increase in fuel revenues. These increases were offset by the effect
of milder temperatures in 1999 as compared to 1998.
The $13 million (25.2 percent) increase in other operating revenues in 1999
as compared to 1998 was due primarily to an increase in steam sales in
conjunction with the operation of the Company's co-generation facilities. The
increase is the result of two new co-generation facilities placed in service in
1999.
Retail revenues in 1998 increased $270 million (10.7 percent) over 1997. The
predominant factors causing the rise in revenues in 1998 were the positive
impact of weather on energy sales, continued growth throughout the state, and
3
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
increased fuel revenues. Fuel revenues were higher in 1998 as compared to 1997
due to higher fuel costs and an increase in purchased power. Fuel revenues
generally represent the direct recovery of fuel expense, including the fuel
component of purchased energy, and therefore have no effect on net income.
Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy sales and
amounts 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:
1999 1998 1997
-------------------------------------------
(in millions)
Capacity $122 $142 $136
Energy 112 118 135
------------------------------------------------------------
Total $234 $260 $271
=============================================================
Capacity revenues from non-affiliates decreased 13.9 percent in 1999
compared to the prior year. This decrease is attributable to the lowering of the
equity return under formula rate contracts, as well as other adjustments and
true-ups related to contractual pricing. Capacity revenues from non-affiliates
in 1998 increased 4.1 percent compared to 1997.
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 1999 and the percent change by year were as
follows:
KWH Percent Change
-------------------------------------------
1999 1999 1998 1997
-------------------------------------------
(millions)
Residential 15,699 (0.6)% 10.2% (1.8)%
Commercial 12,314 3.4 5.1 3.9
Industrial 21,943 1.7 4.2 3.6
Other 201 2.3 8.3 (6.3)
-----------
Total retail 50,157 1.4 6.2 1.9
Sales for resale -
Non-affiliates 12,438 5.0 (3.2) 29.9
Affiliates 5,032 (15.8) (33.5) (12.6)
-----------
Total 67,627 0.5% (0.9)% 3.7%
- ------------------------------------------------------------------
The increases in 1999 and 1998 retail energy sales were primarily due to the
strength of business and economic conditions in the Company's service area. In
1998, residential energy sales experienced a 10.2 percent increase over the
prior year primarily as a result of hot weather in the second quarter, compared
to very mild weather in the second quarter of 1997. Assuming normal weather,
sales to retail customers are projected to grow approximately 2.9 percent
annually on average during 2000 through 2004.
Expenses
Total operating expenses of $2.5 billion for 1999 were down $13.4 million or 0.5
percent compared with 1998. This decrease was mainly due to a $15 million
decrease in fuel and purchased power costs and a $23 million decrease in
maintenance expense, offset by an increase in taxes other than income taxes of
$12 million.
Total operating expenses of $2.5 billion for 1998 were up $203 million or
8.8 percent compared with 1997. This increase was mainly due to a $107 million
increase in purchased power expenses, accompanied by a $58 million increase in
maintenance expense.
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
4
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
fuel per net KWH generated were as follows:
----------------------------
1999 1998 1997
----------------------------
Total generation
(billions of KWHs) 63 63 65
Sources of generation
(percent) --
Coal 72 72 72
Nuclear 20 18 20
Hydro 5 8 8
Oil & Gas 3 2 *
Average cost of fuel per net
KWH generated
(cents) -- 1.44 1.54 1.49
- ----------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.
Total fuel and purchased power costs of $1.1 billion in 1999 decreased $15
million (1 percent), while total energy sales increased 329 million kilowatt
hours (0.5 percent) compared with the amounts recorded in 1998. Continued
efforts to control energy costs helped lower the average cost of fuel per net
kilowatt hour generated in 1999.
Fuel and purchased power costs in 1998 increased $111 million (11 percent)
over 1997 due primarily to lower levels of nuclear and hydro generation, which
were replaced by the use of peaking units and purchased power.
Purchased power consists primarily of purchases from affiliates in the
Southern electric system. 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.
The 7.5 percent decrease in maintenance expense in 1999 as compared to 1998
is primarily attributable to a decrease in distribution expenses. The 23.8
percent increase in maintenance expenses in 1998 is attributable to (i) an
increase in the maintenance of overhead lines, (ii) the write-off of obsolete
steam and nuclear generating plant inventory, and (iii) additional accruals to
partially replenish the natural disaster reserve.
Depreciation and amortization expense increased 2.6 percent in 1999 and
1998. These increases reflect additions to property, plant, and equipment.
Taxes other than income taxes increased $12 million (6.0 percent) in 1999 as
compared to 1998. This increase is attributable to increases in real and
personal property taxes and public utility license taxes.
Total net interest and other charges decreased $38 million (12.3 percent) in
1999. This decrease results primarily from a decrease in the amortization of
premiums on reacquired debt pursuant to an APSC order. Total net interest and
other charges increased $55.7 million (22 percent) in 1998 primarily due to an
increase in the amortization of premiums on reacquired debt, pursuant to an APSC
order. See Note 3 to the financial statements under "Retail Rate Adjustment
Procedures" for additional details.
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 plants 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
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors, including the ability of the Company to achieve energy sales
growth in a less regulated, more competitive environment.
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 APSC under cost-based regulatory principles.
5
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included weather, competition, new short and long-term contracts with
neighboring utilities, energy conservation practiced by customers, the
elasticity of demand, and the rate of economic growth in the Company's
traditional service area.
The electric utility industry in the United States is currently undergoing a
period of dramatic change 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
being driven down by wholesale transmission access and numerous potential new
energy suppliers, including power marketers and brokers. The Company is
aggressively working to maintain and expand its share of wholesale business in
the Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current 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. As these
initiatives materialize, the structure of the utility industry continues to
change. 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 competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of the Company to recover its investments, including the
regulatory assets described in Note 1 to the financial statements, could have a
material adverse effect on the financial condition and results of operations.
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.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
the formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including Southern Company, are required
to make a filing by October 15, 2000. The filing must contain either a proposal
for RTO participation or a description of the efforts made to participate in an
RTO, the reasons for non-participation, any obstacles to participation, and any
plans for further work toward participation. The RTOs that are proposed in the
filings should be operational by December 15, 2001. The Company is evaluating
this issue and formulating its response. The outcome of this matter cannot
presently be determined.
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. In June
1995, the APSC issued an order granting the Company's request for gradual
adjustments to move toward parity among customer classes. This order also calls
for a moratorium on any periodic retail rate increases (but not decreases) until
2001.
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 1997,
the APSC issued an additional order authorizing the Company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the Company. See Note 3 to
the financial statements for
6
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
information about this and other matters.
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 and
regulations 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."
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry --
including the Company -- regarding the recognition, measurement, and
classification in the financial statements of decommissioning costs for nuclear
generating facilities. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to the retirement of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs of
retiring the Company's nuclear and other facilities may be required to be
recorded as liabilities in the Balance Sheets. Also, the annual provisions for
such costs could change. Because of the Company's current ability to recover
asset retirement costs through rates, these changes would not have a significant
adverse effect on results of operations. See Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning" for additional information.
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 operations 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 Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 1, 2001. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.
For the Company, original projected total costs for Year 2000 readiness,
including the Company's share of costs of Southern Nuclear Operating Company,
were approximately $36 million; revised projected costs are $33 million. These
costs include labor necessary to identify, test, and renovate affected devices
and systems, and costs for fulfilling reporting requirements to state and
federal agencies. From its inception through December 31, 1999, the Year 2000
program costs, recognized primarily as expense, amounted to $32 million.
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, 1999,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Also, based on the Company's
overall interest rate exposure at December 31, 1999, a near-term 100 basis point
change in interest rates would not materially affect the financial statements.
7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
FINANCIAL CONDITION
Overview
The Company's financial condition remained stable in 1999. This stability is the
continuation over recent years of growth in retail energy sales and cost control
measures combined with a 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 $809 million in 1999. 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.
Capital Structure
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.4 percent in 1999 and 1998, and 44.7 percent in 1997.
During 1999, the Company issued $650 million of senior notes, the proceeds
of which were used primarily to redeem first mortgage bonds and repay short-term
indebtedness, and the Company redeemed $50 million of preferred stock.
Additionally, in February 1999, Alabama Power Capital Trust III, of which
the Company owns all of the common securities, issued $50 million of auction
rate mandatorily redeemable preferred securities. See Note 9 to the financial
statements for additional information.
Capital Requirements
Capital expenditures are estimated to be $831 million for 2000, $743 million for
2001, and $860 million for 2002. 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 needed for the capital budget, approximately $100
million will be required by the end of 2000 for maturities of first mortgage
bonds. Also, the Company will continue to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
Environmental Matters
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action against the Company in the U. S. District Court. The complaint alleges
violations of the prevention of significant deterioration and 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 a notice of violation to the Company 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. The Company believes that it complied with
applicable laws and EPA regulations and interpretations in effect at the time
the work in question took place. 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. 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.
8
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
In November 1990, the Clean Air Act was signed into law. Title IV of the
Clean Air Act -- the acid rain compliance provision of the law - significantly
affected the integrated Southeast utilities of Southern Company, including
Alabama Power. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $25
million for the Company.
For Phase II sulfur dioxide compliance, the Company currently uses emission
allowances and increased fuel switching, and/or the installation of flue gas
desulfurization equipment at selected plants. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits. Compliance for Phase II increased total
estimated construction expenditures in 1999 by approximately $65 million.
The State of Alabama and the EPA are currently evaluating draft plans to
reach attainment with the one hour standard for ozone in the Birmingham
non-attainment area. Provisions of that plan would require nitrogen oxide
reductions at certain Company facilities by May 2003. The Company estimates the
capital cost to comply with the plan to be approximately $138 million, all of
which remains to be spent.
A significant portion of costs related to the acid rain and ozone
non-attainment provision 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.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision makes the standards significantly
more stringent. In September 1998, the EPA issued the final regional nitrogen
oxide reduction rule to the states for implementation. The final rule affects 22
states including Alabama. The EPA's July 1997 standards and the September 1998
rule are being challenged in the courts by several states and industry groups.
Implementation of the final state rules for these three initiatives could
require substantial further reductions in nitrogen oxide and sulfur dioxide
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.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: additional controls for hazardous
air pollutant emissions and control strategies to reduce regional haze. The
impact of any new standards will depend on the development and implementation of
applicable regulations.
In addition to rules and pending changes to rules under the Clean Air Act,
the Company must comply with other environmental laws and regulations including
water discharge permits, solid and hazardous waste disposal, use of materials
controlled by the Toxic Substances Control Act, and reporting requirements under
the Comprehensive Environmental Response, Compensation, and Liability Act. Under
these various requirements and regulations, the Company could incur costs to
implement water discharge requirements, clean up properties containing hazardous
substances, or replace equipment rendered useless by changing requirements. The
exact impact of any requirements would depend on specific regulatory actions and
cannot be determined at this time.
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.
9
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Southern Company. The impact of new legislation -- if
any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential exists for liability as the
result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company has no restrictions on the
amounts of unsecured indebtedness it may incur. However, to issue additional
first mortgage bonds and preferred stock, the Company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The Company's coverages are at a level that would permit any
necessary amount of security sales at current interest and dividend rates.
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
The Company's 1999 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information. Accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the Company's markets; potential business strategies -- including
acquisitions or dispositions of assets or internal restructuring -- that may be
pursued by Southern Company; state and federal rate regulation; changes in or
application of environmental and other laws and regulations to which the Company
is subject; political, legal and economic conditions and developments; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; and other
factors discussed in the reports--including Form 10-K--filed from time to time
by the Company with the Securities and Exchange Commission.
10
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating Revenues:
Retail sales $2,811,117 $2,780,677 $2,510,809
Sales for resale --
Non-affiliates 415,377 448,973 431,023
Affiliates 92,439 103,562 161,795
Other revenues 66,541 53,161 45,484
- ------------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,385,474 3,386,373 3,149,111
- ------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 855,632 900,309 896,014
Purchased power --
Non-affiliates 93,204 92,998 41,795
Affiliates 180,563 150,897 95,538
Other 531,696 527,954 510,203
Maintenance 277,724 300,383 242,691
Depreciation and amortization 347,574 338,822 330,377
Taxes other than income taxes 204,645 193,049 185,062
- ------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,491,038 2,504,412 2,301,680
- ------------------------------------------------------------------------------------------------------------------------
Operating Income 894,436 881,961 847,431
Other Income (Expense):
Interest income 55,896 68,553 37,844
Equity in earnings of unconsolidated subsidiaries (Note 6) 2,650 5,271 5,250
Other, net (24,861) (37,050) (39,506)
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 928,121 918,735 851,019
- ------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 191,895 192,426 167,172
Interest on notes payable 9,865 11,012 22,787
Amortization of debt discount, premium and expense, net (Note 3) 11,159 42,494 9,645
Other interest charges 32,316 40,008 31,250
Distributions on preferred securities of subsidiary (Note 9) 24,662 22,354 21,763
- ------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 269,897 308,294 252,617
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 658,224 610,441 598,402
Income taxes (Note 8) 241,880 218,575 207,877
- ------------------------------------------------------------------------------------------------------------------------
Net Income 416,344 391,866 390,525
Dividends on Preferred Stock 16,464 14,643 14,586
- ------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 399,880 $ 377,223 $ 375,939
========================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
11
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating Activities:
Net income $ 416,344 $ 391,866 $ 390,525
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 403,332 425,167 394,572
Deferred income taxes and investment tax credits, net 29,039 79,430 (12,429)
Other, net (12,661) (66,739) (11,353)
Changes in certain current assets and liabilities --
Receivables, net 33,509 49,747 (30,268)
Fossil fuel stock (1,344) (9,052) 7,518
Materials and supplies (17,968) 11,932 6,191
Accounts payable (38,556) 26,583 (9,745)
Energy cost recovery, retail (97,869) (95,427) 7,108
Other 5,930 (9,803) 13,318
- -------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 719,756 803,704 755,437
- -------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (809,044) (610,132) (451,167)
Other (72,218) (52,940) (51,791)
- -------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (881,262) (663,072) (502,958)
- -------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 96,824 (306,882) (57,971)
Proceeds --
Other long-term debt 751,650 1,462,990 258,800
Preferred securities 50,000 - 200,000
Preferred stock - 200,000 -
Capital contributions from parent company 204,347 30,000 -
Redemptions --
First mortgage bonds (470,000) (771,108) (74,951)
Other long-term debt (104,836) (107,776) (951)
Preferred stock (50,000) (88,000) (184,888)
Payment of preferred stock dividends (15,788) (15,596) (22,524)
Payment of common stock dividends (399,600) (367,100) (339,600)
Other (15,864) (66,869) (16,024)
- -------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 46,733 (30,341) (238,109)
- -------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (114,773) 110,291 14,370
Cash and Cash Equivalents at Beginning of Period 134,248 23,957 9,587
- -------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 19,475 $ 134,248 $ 23,957
=========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $229,305 $234,360 $209,919
Income taxes (net of refunds) 170,121 188,942 207,653
- -------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
12
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------
Assets 1999 1998
- -----------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
<S> <C> <C>
Cash and cash equivalents $ 19,475 $ 134,248
Receivables --
Customer accounts receivable 265,900 272,872
Unrecovered retail fuel clause revenue 168,627 70,758
Other accounts and notes receivable 42,137 32,394
Affiliated companies 40,083 39,981
Accumulated provision for uncollectible accounts (4,117) (1,855)
Refundable income taxes 17,997 52,117
Fossil fuel stock, at average cost 84,582 83,238
Materials and supplies, at average cost 167,637 149,669
Other 46,011 45,550
- -----------------------------------------------------------------------------------------------------------------
Total current assets 848,332 878,972
- -----------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Note 1) 11,783,078 11,352,838
Less accumulated provision for depreciation 4,901,384 4,666,513
- -----------------------------------------------------------------------------------------------------------------
6,881,694 6,686,325
Nuclear fuel, at amortized cost 106,836 95,575
Construction work in progress 715,153 525,359
- -----------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 7,703,683 7,307,259
- -----------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 6) 34,891 34,298
Nuclear decommissioning trusts (Note 1) 286,653 232,183
Other 12,156 12,915
- -----------------------------------------------------------------------------------------------------------------
Total other property and investments 333,700 279,396
- -----------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 330,405 362,953
Prepaid pension costs 213,971 169,393
Debt expense, being amortized 9,563 8,602
Premium on reacquired debt, being amortized 83,895 83,440
Department of Energy assessments (Note 1) 27,685 31,088
Other 97,470 104,595
- -----------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 762,989 760,071
- -----------------------------------------------------------------------------------------------------------------
Total Assets $9,648,704 $9,225,698
=================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 1999 1998
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Current Liabilities:
Securities due within one year (Note 11) $ 100,943 $ 521,209
Notes payable 96,824 -
Accounts payable --
Affiliated 91,315 79,844
Other 140,842 188,074
Customer deposits 31,704 29,235
Taxes accrued --
Income taxes 100,569 82,219
Other 18,295 17,559
Interest accrued 26,365 38,166
Vacation pay accrued 30,112 28,390
Other 84,267 79,095
- ------------------------------------------------------------------------------------------------------------------
Total current liabilities 721,236 1,063,791
- ------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,190,378 2,646,566
- ------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 1,240,344 1,202,971
Deferred credits related to income taxes (Note 8) 265,102 315,735
Accumulated deferred investment tax credits 260,367 271,611
Employee benefits provisions 82,298 81,115
Prepaid capacity revenues (Note 7) 79,703 96,080
Other 155,901 149,250
- ------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,083,715 2,116,762
- ------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) (Note 9) 347,000 297,000
- ------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 317,512 317,512
- ------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 2,988,863 2,784,067
- ------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $9,648,704 $9,225,698
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
<S> <C> <C> <C> <C> <C>
August 1, 1999 6.375% $ - $ 170,000
March 1, 2000 6.00% 100,000 100,000
January 1, 2003 7.00% - 125,000
February 1, 2003 6.75% - 175,000
2023 through 2024 7.30% - 9.00% 500,000 500,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 600,000 1,070,000
- ----------------------------------------------------------------------------------------------------------------------------------
Senior notes --
5.35% due November 15, 2003 156,200 156,200
7.125% due August 15, 2004 250,000 -
5.49% due November 1, 2005 225,000 225,000
7.125% due October 1, 2007 200,000 -
5.375% due October 1, 2008 160,000 160,000
6.25% to 7.125% due 2010-2048 1,207,622 1,008,800
- ----------------------------------------------------------------------------------------------------------------------------------
Total senior notes 2,198,822 1,550,000
- ----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% to 6.50% due 2023-2024 24,400 126,050
Variable rates (4.75% to 4.85% at 1/1/00)
due 2015-2017 89,800 89,800
Non-collateralized:
7.25% due 2003 - 1,000
Variable rates (3.50% to 6.03% at 1/1/00)
due 2021-2028 425,940 324,290
- ----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 540,140 541,140
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 5,111 6,119
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (52,752) (49,484)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $215.9 million) 3,291,321 3,117,775
Less amount due within one year 100,943 471,209
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $3,190,378 $2,646,566 46.6% 43.8%
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
15
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION (continued) At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
<S> <C> <C> <C> <C>
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
7.375% $ 97,000 $97,000
7.60% 200,000 200,000
Auction rate (6.42% at 1/1/00) 50,000 -
- ---------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $25.6 million) 347,000 297,000 5.1 4.9
- ----------------------------------------------------------------------------------------------------------------------------------
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 1/1/00
4.22% to 4.50% 70,000 120,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $15.9 million) 317,512 367,512
Less amount due within one year - 50,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year 317,512 317,512 4.6 5.2
- ----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 6,000,000 shares
Outstanding - 5,608,955 shares in 1999 and 1998
Par value 224,358 224,358
Paid-in capital 1,538,992 1,334,645
Premium on Preferred Stock 99 99
Retained earnings 1,225,414 1,224,965
- ----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 2,988,863 2,784,067 43.7 46.1
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $6,843,753 $6,045,145 100.0% 100.0%
==================================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
16
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1997 $224,358 $1,304,645 $146 $1,185,128 $2,714,277
Net income after dividends on preferred stock - - - 375,939 375,939
Cash dividends on common stock - - - (339,600) (339,600)
Other - - (47) - (47)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 224,358 1,304,645 99 1,221,467 2,750,569
Net income after dividends on preferred stock - - - 377,223 377,223
Capital contributions from parent company - 30,000 - - 30,000
Cash dividends on common stock - - - (367,100) (367,100)
Other - - - (6,625) (6,625)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 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
=============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>
17
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1999 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 integrated Southeast utilities,
Southern Company Services (SCS), Southern Communications Services (Southern
LINC), Southern Company Energy Solutions, Southern Energy, Inc. (Southern
Energy), Southern Nuclear Operating Company (Southern Nuclear), and other direct
and indirect subsidiaries. The integrated Southeast utilities --Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company-- provide electric service in four
states. Contracts among the integrated Southeast utilities - 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). SCS
provides, at cost, specialized services to Southern Company and its subsidiary
companies. Southern LINC provides digital wireless communications services to
the integrated Southeast utilities and also markets these services to the public
within the Southeast. Southern Company Energy Solutions develops new business
opportunities related to energy products and services. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Energy acquires,
develops, builds, owns, and operates power production and delivery facilities
and provides a broad range of energy-related services to utilities and
industrial companies in selected countries around the world. Southern Energy
businesses include independent power projects, integrated utilities, a
distribution company, and energy trading and marketing businesses outside the
southeastern United States.
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 generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by its respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from
those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Related-Party Transactions
The Company has an agreement with SCS 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, human resources, systems and
procedures, and other services with respect to business and operations and power
pool transactions. Costs for these services amounted to $218 million, $201
million, and $154 million during 1999, 1998, and 1997, 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 $135 million, $137 million,
and $117 million during 1999, 1998, and 1997, respectively.
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 to the Company
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.
18
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:
1999 1998
-----------------------
(in millions)
Deferred income tax charges $ 330 $ 363
Deferred income tax credits (265) (316)
Premium on reacquired debt 84 83
Department of Energy assessments 28 31
Vacation pay 30 28
Natural disaster reserve (19) (19)
Other, net 59 51
- ----------------------------------------------------------------
Total $ 247 $ 221
================================================================
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. The
Company accrues revenues for services rendered but unbilled at the end of each
fiscal period. Fuel costs are expensed as the fuel is used. The Company's
electric rates include provisions to adjust billings for fluctuations in fuel
and the energy component of purchased power costs. Revenues are adjusted for
differences between recoverable fuel costs and amounts actually recovered in
current regulated rates.
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 $63
million in 1999, $59 million in 1998, and $68 million in 1997. 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 storage capacity currently is available to permit operation into 2009
and 2013 at Plant Farley units 1 and 2, respectively. Planning for additional
on-site spent fuel storage capacity at Plant Farley is in progress, with the
intent to place additional on-site spent fuel storage capacity in operation as
early as 2005. In addition, through Southern Nuclear, the Company is a member of
Private Fuel Storage, LLC, a joint utility effort to develop a private spent
fuel storage facility for temporary storage of spent nuclear fuel. This facility
is planned to begin operation as early as the year 2003.
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 will be
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 at December 31, 1999, under this law to be approximately $28 million.
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 1999 and 1998, and 3.3 percent in 1997. 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 the 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.
Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial nuclear power reactors to establish a plan for providing,
with reasonable assurance, funds for decommissioning. The Company has
19
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
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. 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 1999 and fund balances as of
December 31, 1999 were:
(in millions)
Amount expensed in 1999 $ 18
-------------------------------------------------------------
Accumulated provisions:
External trust funds, at fair value $ 287
Internal reserves 40
-------------------------------------------------------------
Total $ 327
=============================================================
All of the Company's decommissioning costs are approved for ratemaking.
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 composite rate used to determine the amount of
allowance was 8.8 percent in 1999, 9.0 percent in 1998, and 5.8 percent in 1997.
AFUDC, net of income tax, as a percent of net income after dividends on
preferred stock was 4.7 percent in 1999, 1.8 percent in 1998, and 0.8 percent in
1997.
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
20
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
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
The Company's financial instruments for which the carrying amount did not
approximate fair value at December 31 are as follows:
Carrying Fair
Amount Value
-------------------------
(in millions)
Long-term debt:
At December 31, 1999 $3,286 $3,045
At December 31, 1998 3,112 3,195
Preferred Securities:
At December 31, 1999 347 299
At December 31, 1998 297 307
--------------------------------------------------------------
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 September 1994, in response to a request by the Company, the APSC issued an
order allowing the Company to establish a Natural Disaster Reserve. Regulatory
treatment allows the Company to accrue $250 thousand per month, until the
maximum accumulated provision of $32 million is attained. However, in December
1995, the APSC approved higher accruals to restore the reserve to its authorized
level whenever the balance in the reserve declines below $22.4 million. At
December 31, 1999, the reserve balance was $19 million.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, pension plans that cover
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 FERC. 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:
1999 1998
- ---------------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00 4.25
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
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $868 $813
Service cost 23 22
Interest cost 57 59
Benefits paid (51) (51)
Actuarial (gain) loss and
employee transfers (24) 25
- ---------------------------------------------------------------
Balance at end of year $873 $868
===============================================================
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,461 $1,521
Actual return on plan assets 245 9
Benefits paid (51) (51)
Employee transfers (8) (18)
- ---------------------------------------------------------------
Balance at end of year $1,647 $1,461
===============================================================
21
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
The accrued pension costs recognized in the Balance Sheets were as
follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $ 774 $ 593
Unrecognized transition obligation (25) (30)
Unrecognized prior service cost 36 39
Unrecognized net actuarial gain (571) (433)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 214 $ 169
===============================================================
Components of the pension plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 23 $ 22 $ 20
Interest cost 57 59 58
Expected return on plan assets (109) (102) (95)
Recognized net actuarial gain (14) (16) (13)
Net amortization (2) (2) (2)
- ---------------------------------------------------------------
Net pension income $ (45) $ (39) $(32)
===============================================================
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
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $278 $252
Service cost 5 5
Interest cost 18 19
Benefits paid (10) (12)
Actuarial (gain) loss and
employee transfers (27) 14
- ---------------------------------------------------------------
Balance at end of year $264 $278
===============================================================
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $137 $125
Actual return on plan assets 18 4
Employer contributions 16 20
Benefits paid (10) (12)
- ---------------------------------------------------------------
Balance at end of year $161 $137
===============================================================
The accrued postretirement costs recognized in the Balance Sheets were
as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $(103) $(141)
Unrecognized transition obligation 53 57
Unrecognized net actuarial
(gain) loss (12) 22
Fourth quarter contributions 8 8
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (54) $ (54)
===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 5 $ 5 $ 4
Interest cost 18 18 18
Expected return on plan assets (11) (9) (7)
Net amortization 4 4 4
- ---------------------------------------------------------------
Net postretirement cost $ 16 $ 18 $ 19
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 percent through the year 2005,
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,
1999 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $ 17 $ (15)
Service and interest costs 1 (1)
===============================================================
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The
costs related to these programs were $5.6 million, $19.4 million and $33.0
million for the years 1999, 1998 and 1997, respectively. In addition, certain
costs of these programs were deferred and are being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $1.2 million at
December 31, 1999.
22
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
3. CONTINGENCIES AND REGULATORY
MATTERS
Lake Martin Litigation
On November 30, 1998, total judgments of nearly $53 million were entered in
favor of five plaintiffs against the Company and two large textile
manufacturers. The plaintiffs alleged that the manufacturers had discharged
certain polluting substances into a stream that empties into Lake Martin, a
hydroelectric reservoir owned by the Company, and that such discharges
had reduced the value of the plaintiffs' residential lots on Lake Martin. Of the
total amount of the judgments, $155 thousand was compensatory damages and the
remainder was punitive damages. The damages were assessed against all three
defendants jointly. The Company has appealed these judgments to the Supreme
Court of Alabama. While the Company believes that these judgments should be
reversed or set aside, the final outcome of this matter cannot now be
determined.
Additional actions have been filed by other landowners in the same
subdivision on Lake Martin against the same defendants, including the Company.
The plaintiffs assert substantially the same allegations as in the current
proceeding being appealed. The final outcome of these actions cannot now be
determined.
Environmental Protection Agency Litigation
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action against the Company in the U. S. District Court. The complaint alleges
violations of the prevention of significant deterioration and new source review
provision 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 beginning at the
point of the alleged violations. The EPA concurrently issued a notice of
violation to the Company 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. 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. 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. 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
In November 1982, the APSC 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 in retail service. Both increases and decreases have been
placed into effect since the adoption of these rates. 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 June 1995, the APSC issued a rate order granting the Company's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
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 1997,
the APSC issued an additional order authorizing the Company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the Company. In 1998, the
Company - in accordance with the 1995 rate order - recorded $33 million of
additional amortization of premium on reacquired debt. The Company did not
record any additional amounts in 1999 or 1997.
23
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
The Company's ratemaking procedures will remain in effect until the APSC
votes to modify or discontinue them.
4. CAPITAL BUDGET
The Company's capital expenditures are currently estimated to total $831 million
in 2000, $743 million in 2001, and $860 million in 2002. Some of the more
significant items included in the Company's capital budget are as follows:
(i) The Company is replacing all six steam generators at Plant Farley. The
estimated remaining costs associated with this project, which will be
completed in 2001, amount to $100 million.
(ii) The Company is also constructing and installing 1,075 megawatts of capacity
and associated substation facilities at Plant Barry. Half of the capacity
is scheduled to go in service in 2000, with the remainder going in service
in 2001. The remaining projected expenditures related to these facilities
are $181 million.
(iii)Cogeneration facilities, with a capacity of 200 megawatts, are being
constructed in Theodore, Alabama, and will go in service in 2001. The
estimated remaining costs associated with this project total $81 million.
(iv) The capital budget reflects $472 million related to projected generation
capacity scheduled to be placed into service in 2003 and beyond.
In addition to the above items, significant construction will continue
related to transmission and distribution facilities and the upgrading of
generating plants.
The capital budget is subject to periodic review and revision, and actual
capital costs incurred 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.
5. FINANCING AND COMMITMENTS
General
To the extent possible, the Company's construction program is expected to be
financed primarily from internal sources. Short-term debt is often utilized and
the amounts available are discussed below. The Company may issue additional
long-term debt and preferred securities for debt maturities, redeeming
higher-cost securities, and meeting additional capital requirements.
Financing
The ability of the Company to finance its capital budget depends on the amount
of funds generated internally and the funds it can raise by external financing.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company has no restrictions on the
amounts of unsecured indebtedness it may incur. However, to issue additional
first mortgage bonds and preferred stock, the Company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The most restrictive of these provisions requires, for the
issuance of additional first mortgage bonds, that before-income-tax earnings, as
defined, cover pro forma annual interest charges on outstanding first mortgage
bonds at least twice; and for the issuance of additional preferred stock, that
gross income available for interest cover pro forma annual interest charges and
preferred stock dividends at least one and one-half times. The Company's
coverages are at a level that would permit any necessary amount of security
sales at current interest and dividend rates.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $907 million
(including $418 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$517 million expire at various times during 2000 and $390 million expire in
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
24
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
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.
At December 31, 1999, the Company had regulatory approval to have
outstanding up to $750 million 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.
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, 1999, were as follows:
Year Commitments
- ---- ----------------
(in millions)
2000 $ 715
2001 672
2002 561
2003 469
2004 472
2005 - 2026 2,019
- ---------------------------------------------------------------
Total commitments $4,908
===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $17.8 million in 1999, $5.8 million
in 1998, and $3.0 million in 1997. At December 31, 1999, estimated minimum
rental commitments for noncancellable operating leases were as follows:
Year Commitments
- ---- -----------------
(in millions)
2000 $ 20.0
2001 19.6
2002 19.2
2003 18.8
2004 18.4
2005 - 2017 64.3
- --------------------------------------------------------------
Total minimum payments $160.3
==============================================================
6. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power Company 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 transmission facilities. The capacity of these units is sold equally
to the Company and Georgia Power Company 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 $92 million in 1999, $74 million
in 1998 and $73 million in 1997, 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 Company 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.
25
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
At December 31, 1999, the capitalization of SEGCO consisted of $50 million
of equity and $72 million of long-term debt on which the annual interest
requirement is $4.3 million. SEGCO paid dividends totaling $4.3 million in 1999,
$8.7 million in 1998, and $10.6 million in 1997, of which one-half of each was
paid to the Company. SEGCO's net income was $5.4 million, $7.5 million, and $8.5
million for 1999, 1998 and 1997, respectively.
The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1999, 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 $ 97 $ 45
Plant Miller
Units 1 and 2 740 297
----------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the operating affiliates of Southern Company have entered into
long-term contractual agreements for the sale 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 pertain
to capacity related to specific generating units. Because the energy is
generally sold at cost under these agreements, profitability is primarily
affected by revenues from capacity sales. The Company's capacity revenues
amounted to $122 million in 1999, $142 million in 1998, and $136 million in
1997.
Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority
(JEA) and the City of Tallahassee, Florida. Under these agreements,
approximately 1,250 megawatts of capacity are scheduled to be sold through 2000.
Thereafter, these sales will remain at that approximate level -- unless reduced
by FP&L, FPC, and JEA for the periods after 2000 with a minimum of three years
notice -- until the expiration of the contracts in 2010.
Alabama Municipal Electric Authority (AMEA)
Capacity Contracts
In August 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 commencing September 1, 1986 (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 commencing October 1, 1991 (1991 Contract).
In both contracts the power will be sold to AMEA for its member municipalities
that previously were served directly by the Company as wholesale customers.
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. These
payments are being recognized as operating revenues and the discounts are being
amortized to other interest expense as scheduled capacity is made available over
the terms of the contracts.
In order 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 occurs. As the liquidated damages decline under the contracts, a portion
of the bonds equal to the decreases are returned to the Company. At December 31,
1999, $81.5 million of such bonds was held by the escrow agent under the
contracts.
8. INCOME TAXES
At December 31, 1999, the tax-related regulatory assets and liabilities were
$330 million and $265 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
26
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
to capitalized AFUDC. 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:
1999 1998 1997
--------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $194 $123 $197
Deferred --
Current year (6) 59 33
Reversal of prior years 30 13 (44)
- -----------------------------------------------------------------
218 195 186
- -----------------------------------------------------------------
State --
Current 19 16 23
Deferred --
Current year 1 5 1
Reversal of prior years 4 2 (2)
- -----------------------------------------------------------------
24 23 22
- -----------------------------------------------------------------
Total $242 $218 $208
=================================================================
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:
1999 1998
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 884 $ 861
Property basis differences 419 435
Fuel cost adjustment 65 29
Premium on reacquired debt 31 29
Pensions 60 50
Other 11 17
- -----------------------------------------------------------------
Total 1,470 1,421
- -----------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 24 28
Other deferred costs 25 25
Postretirement benefits 22 20
Unbilled revenue 13 16
Other 63 56
- -----------------------------------------------------------------
Total 147 145
- -----------------------------------------------------------------
Net deferred tax liabilities 1,323 1,276
Portion included in current liabilities, net (83) (73)
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,240 $1,203
=================================================================
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 1999, 1998, and 1997. At December 31, 1999, 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:
1999 1998 1997
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.4 2.5 2.4
Non-deductible book
depreciation 1.6 1.5 1.5
Differences in prior years'
deferred and current tax rates (1.3) (1.6) (2.3)
Other (0.9) (1.6) (1.9)
- ---------------------------------------------------------------
Effective income tax rate 36.8% 35.8% 34.7%
===============================================================
27
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis.
9. COMPANY OBLIGATED 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. In February 1999, Alabama Power Capital Trust III (Trust III), of which
the Company owns all of the common securities, issued $50 million of auction
rate mandatorily redeemable preferred securities. The distribution rate of these
variable securities was 6.42% at January 1, 2000.
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.
10. OTHER LONG-TERM DEBT
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 $215.9 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 1997, 1998, and 1999 the Company issued unsecured senior notes. The senior
notes are, in effect, subordinated to all secured debt of the Company, including
its first mortgage bonds.
The estimated aggregate annual maturities of capitalized lease obligations
through 2004 are as follows: $0.9 million in 2000, $0.8 million in 2001, $0.9
million in 2002, $0.9 million in 2003 and $1.0 million in 2004.
11. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt and preferred stock due within one year at
December 31 is as follows:
1999 1998
------------------------
(in thousands)
First mortgage bond maturities
and redemptions $100,000 $470,000
Other long-term debt maturities
(Note 10) 943 1,209
-------------------------------------------------------------
Total long-term debt due within
one year 100,943 471,209
-------------------------------------------------------------
Preferred stock to be redeemed - 50,000
-------------------------------------------------------------
Total $100,943 $521,209
=============================================================
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.
12. 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
28
<PAGE>
NOTES (continued)
Alabama Power Company 1999 Annual Report
that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $200 million by private insurance, 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 be insured against increased costs of replacement power in an
amount up to $3.5 million per week (starting 12 weeks after the outage) for one
year and up to $2.8 million per week for the second and third 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 $19 million.
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.
13. COMMON STOCK 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, 1999, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.
14. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 1999 and 1998 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- -------------------- --------------------------------------------
(in millions)
March 1999 $ 714 $162 $ 63
June 1999 823 209 93
September 1999 1,116 388 201
December 1999 733 136 43
March 1998 $ 717 $173 $ 66
June 1998 864 235 95
September 1998 1,058 342 174
December 1998 748 132 42
- -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
29
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Alabama Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Revenues (in thousands) $3,385,474 $3,386,373 $3,149,111 $3,120,775 $3,024,774
Net Income after Dividends
on Preferred Stock (in thousands) $399,880 $377,223 $375,939 $371,490 $360,894
Cash Dividends
on Common Stock (in thousands) $399,600 $367,100 $339,600 $347,500 $285,000
Return on Average Common Equity (percent) 13.85 13.63 13.76 13.75 13.61
Total Assets (in thousands) $9,648,704 $9,225,698 $8,812,867 $8,733,846 $8,744,360
Gross Property Additions (in thousands) $809,044 $610,132 $451,167 $425,024 $551,781
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $2,988,863 $2,784,067 $2,750,569 $2,714,277 $2,690,374
Preferred stock 317,512 317,512 255,512 340,400 440,400
Company obligated mandatorily
redeemable preferred securities 347,000 297,000 297,000 97,000 -
Long-term debt 3,190,378 2,646,566 2,473,202 2,354,006 2,374,948
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $6,843,753 $6,045,145 $5,776,283 $5,505,683 $5,505,722
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 43.7 46.1 47.6 49.3 48.9
Preferred stock 4.6 5.3 4.4 6.2 8.0
Company obligated mandatorily
redeemable preferred securities 5.1 4.9 5.2 1.7 -
Long-term debt 46.6 43.7 42.8 42.8 43.1
- ----------------------------------------------------------------------------------------------------------------------------------
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+
Duff & Phelps AA- AA- AA- AA- A+
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's A- A A A A
Duff & Phelps A A A+ A+ A
Unsecured Long-Term Debt -
Moody's A2 A2 A2 - -
Standard and Poor's A A A - -
Duff & Phelps A+ A+ A+ - -
==================================================================================================================================
Customers (year-end):
Residential 1,120,574 1,106,217 1,092,161 1,073,559 1,058,197
Commercial 188,368 182,738 177,362 171,827 166,480
Industrial 4,897 5,020 5,076 5,100 5,338
Other 735 733 728 732 725
- ----------------------------------------------------------------------------------------------------------------------------------
Total 1,314,574 1,294,708 1,275,327 1,251,218 1,230,740
==================================================================================================================================
Employees (year-end): 6,792 6,631 6,531 6,865 7,261
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Alabama Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Revenues (in thousands):
Residential $ 1,145,646 $1,133,435 $ 997,507 $ 998,806 $ 997,069
Commercial 807,098 779,169 724,148 696,453 670,453
Industrial 843,090 853,550 775,591 759,628 805,596
Other 15,283 14,523 13,563 13,729 13,619
- ---------------------------------------------------------------------------------------------------------------------------------
Total retail 2,811,117 2,780,677 2,510,809 2,468,616 2,486,737
Sales for resale - non-affiliates 415,377 448,973 431,023 391,669 370,140
Sales for resale - affiliates 92,439 103,562 161,795 216,620 127,730
- ---------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,318,933 3,333,212 3,103,627 3,076,905 2,984,607
Other revenues 66,541 53,161 45,484 43,870 40,167
- ---------------------------------------------------------------------------------------------------------------------------------
Total $3,385,474 $3,386,373 $3,149,111 $3,120,775 $3,024,774
=================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 15,699,081 15,794,543 14,336,408 14,593,761 14,383,231
Commercial 12,314,085 11,904,509 11,330,312 10,904,476 10,043,220
Industrial 21,942,889 21,585,117 20,727,912 19,999,258 19,862,577
Other 201,149 196,647 180,389 192,573 186,848
- ---------------------------------------------------------------------------------------------------------------------------------
Total retail 50,157,204 49,480,816 46,575,021 45,690,068 44,475,876
Sales for resale - non-affiliates 12,437,599 11,840,910 12,329,480 9,491,237 8,046,189
Sales for resale - affiliates 5,031,781 5,976,099 8,993,326 10,292,066 6,705,174
- ---------------------------------------------------------------------------------------------------------------------------------
Total 67,626,584 67,297,825 67,897,827 65,473,371 59,227,239
=================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.30 7.18 6.96 6.84 6.93
Commercial 6.55 6.55 6.39 6.39 6.68
Industrial 3.84 3.95 3.74 3.80 4.06
Total retail 5.60 5.62 5.39 5.40 5.59
Sales for resale 2.91 3.10 2.78 3.07 3.38
Total sales 4.91 4.95 4.57 4.70 5.04
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,097 14,370 13,254 13,705 13,686
Residential Average Annual
Revenue Per Customer $1,028.76 $1,031.21 $922.21 $937.95 $948.71
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 11,151 11,151 11,151 11,151 10,831
Maximum Peak-Hour Demand (megawatts):
Winter 8,863 7,757 8,478 8,413 7,958
Summer 10,739 10,329 9,778 9,912 10,090
Annual Load Factor (percent) 59.7 62.9 62.7 61.3 59.2
Plant Availability (percent):
Fossil-steam 80.4 85.6 86.3 86.6 88.3
Nuclear 91.0 80.2 88.8 90.5 81.1
- ---------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 64.1 65.3 65.7 67.0 67.1
Nuclear 17.8 16.3 17.9 18.5 17.1
Hydro 4.7 6.9 7.5 7.1 7.0
Oil and gas 1.1 1.5 0.7 0.4 0.4
Purchased power -
From non-affiliates 4.5 3.3 2.4 2.4 2.7
From affiliates 7.8 6.7 5.8 4.6 5.7
- ---------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
=================================================================================================================================
</TABLE>
31
