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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2001
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-3526 The Southern Company 58-0690070
(A Delaware Corporation)
270 Peachtree Street, N.W.
Atlanta, Georgia 30303
(404) 506-5000
1-3164 Alabama Power Company 63-0004250
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35291
(205) 257-1000
1-6468 Georgia Power Company 58-0257110
(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia 30308
(404) 506-6526
0-2429 Gulf Power Company 59-0276810
(A Maine Corporation)
One Energy Place
Pensacola, Florida 32520
(850) 444-6111
0-6849 Mississippi Power Company 64-0205820
(A Mississippi Corporation)
2992 West Beach
Gulfport, Mississippi 39501
(228) 864-1211
1-5072 Savannah Electric and Power Company 58-0418070
(A Georgia Corporation)
600 East Bay Street
Savannah, Georgia 31401
(912) 644-7171
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Securities registered pursuant to Section 12(b) of the Act:1
Each of the following classes or series of securities registered pursuant to
Section 12(b) of the Act is registered on the New York Stock Exchange.
Title of each class Registrant
- ------------------- -----------
Common Stock, $5 par value The Southern Company
Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.75% Cumulative Quarterly Income Preferred Securities 2
7 1/8% Trust Originated Preferred Securities3
6.875% Cumulative Quarterly Income Preferred Securities4
---------------------------------------------------
Class A preferred, cumulative, $25 stated capital Alabama Power Company
5.20% Series 5.83% Series
Senior Notes
7 1/8% Series A 7% Series C
7% Series B 6.75% Series J
Company obligated mandatorily redeemable
preferred securities, $25 liquidation
amount
7.375% Trust Preferred Securities5
7.60% Trust Originated Preferred Securities6
---------------------------------------------------
Senior Notes Georgia Power Company
6 7/8% Series A 6 5/8% Series D
6.60% Series B
Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.75% Trust Preferred Securities7 7.60% Trust Preferred Securities8
7.75% Cumulative Quarterly Income Preferred Securities9
6.85% Trust Preferred Securities10
------------------------------------------------------
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- ----------------------------
1 As of December 31, 2001.
2 Issued by Southern Company Capital Trust III and guaranteed by The Southern
Company.
3 Issued by Southern Company Capital Trust IV and guaranteed by The Southern
Company.
4 Issued by Southern Company Capital Trust V and guaranteed by The Southern
Company.
5 Issued by Alabama Power Capital Trust I and guaranteed by Alabama Power
Company.
6 Issued by Alabama Power Capital Trust II and guaranteed by Alabama Power
Company.
7 Issued by Georgia Power Capital Trust I and guaranteed by Georgia Power
Company.
8 Issued by Georgia Power Capital Trust II and guaranteed by Georgia Power
Company.
9 Issued by Georgia Power Capital Trust III and guaranteed by Georgia Power
Company.
10 Issued by Georgia Power Capital Trust IV and guaranteed by Georgia Power
Company.
Company obligated mandatorily redeemable Gulf Power Company
preferred securities, $25 liquidation amount
7.625% Cumulative Quarterly Income Preferred Securities11
7.00% Cumulative Quarterly Income Preferred Securities12
7.375% Trust Preferred Securities13
------------------------------------------------------
Depositary preferred shares, Mississippi Power Company
each representing
one-fourth of a share of preferred stock,
cumulative, $100 par value
6.32%Series 6.65% Series
Company obligated mandatorily redeemable
preferred securities, $25 liquidation
amount
7.75% Trust Originated Preferred Securities14
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Company obligated mandatorily Savannah Electric and Power Company
redeemable preferred securities,
$25 liquidation amount
6.85% Trust Preferred Securities15
Securities registered pursuant to Section 12(g) of the Act:16
Title of each class Registrant
- ------------------- ----------
Preferred stock, cumulative, $100 par value Alabama Power Company
4.20% Series 4.60% Series 4.72% Series
4.52% Series 4.64% Series 4.92% Series
Class A preferred, cumulative, $100,000 stated capital
Auction (1993 Series)
Class A preferred, cumulative, $100 stated capital
Auction (1988 Series)
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Preferred stock, cumulative, Georgia Power Company
$100 stated value
$4.60 Series (1954)
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- ---------------------
11 Issued by Gulf Power Capital Trust I and guaranteed by Gulf Power Company.
12 Issued by Gulf Power Capital Trust II and guaranteed by Gulf Power Company.
13 Issued by Gulf Power Capital Trust III and guaranteed by Gulf Power Company.
14 Issued by Mississippi Power Capital Trust I and guaranteed by Mississippi
Power Company.
15 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah
Electric and Power Company.
16 As of December 31, 2001.
Preferred stock, cumulative, $100 par value Gulf Power Company
4.64% Series 5.44% Series
5.16% Series
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Preferred stock, cumulative, $100 par value Mississippi Power Company
4.40% Series 4.60% Series
4.72% Series 7.00% Series
----------------------------------------------------------
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ( )
Aggregate market value of voting stock held by non-affiliates of
The Southern Company at February 28, 2002: $17.8 billion. Each of such other
registrants is a wholly-owned subsidiary of The Southern Company. A description
of registrants' common stock follows:
Description of Shares Outstanding
Registrant Common Stock at February 28, 2002
- ---------- ------------ --------------------
The Southern Company Par Value $5 Per Share 700,085,336
Alabama Power Company Par Value $40 Per Share 6,000,000
Georgia Power Company No Par Value 7,761,500
Gulf Power Company No Par Value 992,717
Mississippi Power Company Without Par Value 1,121,000
Savannah Electric and Power Company Par Value $5 Per Share 10,844,635
Documents incorporated by reference: specified portions of The Southern
Company's Proxy Statement relating to the 2002 Annual Meeting of Stockholders
are incorporated by reference into PART III. In addition, specified portions of
the Information Statements of Alabama Power Company, Georgia Power Company, Gulf
Power Company and Mississippi Power Company relating to each of their respective
2002 Annual Meeting of Shareholders are incorporated by reference into PART III.
This combined Form 10-K is separately filed by The Southern Company, Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company and Savannah Electric and Power Company. Information contained herein
relating to any individual company is filed by such company on its own behalf.
Each company makes no representation as to information relating to the other
companies.
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Table of Contents
Page
PART I
Item 1 Business
Mirant Corporation........................................................ I-1
The SOUTHERN System....................................................... I-2
Operating Companies....................................................... I-2
Southern Power............................................................ I-2
Other Business............................................................ I-3
Certain Factors Affecting the Industry.................................... I-3
Construction Programs..................................................... I-4
Financing Programs........................................................ I-6
Fuel Supply............................................................... I-7
Territory Served by the Operating Companies............................... I-8
Competition............................................................... I-11
Regulation................................................................ I-13
Rate Matters.............................................................. I-16
Employee Relations........................................................ I-18
Item 2 Properties.................................................................. I-20
Item 3 Legal Proceedings........................................................... I-24
Item 4 Submission of Matters to a Vote of Security Holders......................... I-27
Executive Officers of SOUTHERN.............................................. I-28
Executive Officers of ALABAMA............................................... I-29
Executive Officers of GEORGIA............................................... I-30
Executive Officers of GULF.................................................. I-31
Executive Officers of MISSISSIPPI........................................... I-32
PART II
Item 5 Market for Registrants' Common Equity and Related Stockholder Matters....... II-1
Item 6 Selected Financial Data..................................................... II-2
Item 7 Management's Discussion and Analysis of Results of Operations
and Financial Condition................................................... II-2
Item 7A Quantitative and Qualitative Disclosures about Market Risk.................. II-2
Item 8 Financial Statements and Supplementary Data................................. II-3
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure....................................... II-4
PART III
Item 10 Directors and Executive Officers of the Registrants........................ III-1
Item 11 Executive Compensation..................................................... III-3
Item 12 Security Ownership of Certain Beneficial Owners and
Management............................................................... III-9
Item 13 Certain Relationships and Related Transactions............................. III-10
PART IV
Item 14 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K.............................................................. IV-1
i
DEFINITIONS
When used in Items 1 through 5 and Items 10 through 14, the following terms
will have the meanings indicated.
Term Meaning
AEC........................................... Alabama Electric Cooperative, Inc.
AFUDC......................................... Allowance for Funds Used During Construction
ALABAMA....................................... Alabama Power Company
AMEA.......................................... Alabama Municipal Electric Authority
Clean Air Act................................. Clean Air Act Amendments of 1990
Dalton........................................ City of Dalton, Georgia
DOE........................................... United States Department of Energy
EMF........................................... Electromagnetic field
Energy Act.................................... Energy Policy Act of 1992
Energy Solutions.............................. Southern Company Energy Solutions, Inc.
Entergy Gulf States........................... Entergy Gulf States Utilities Company
EPA........................................... United States Environmental Protection Agency
FERC.......................................... Federal Energy Regulatory Commission
FPC........................................... Florida Power Corporation
FP&L.......................................... Florida Power & Light Company
GEORGIA....................................... Georgia Power Company
GULF.......................................... Gulf Power Company
Holding Company Act........................... Public Utility Holding Company Act of 1935, as amended
IBEW.......................................... International Brotherhood of Electrical Workers
IPP........................................... Independent power producer
IRP........................................... Integrated Resource Plan
IRS........................................... Internal Revenue Service
JEA........................................... Jacksonville Electric Authority
MEAG.......................................... Municipal Electric Authority of Georgia
MESH.......................................... Mobile Energy Services Holdings
Mirant........................................ Mirant Corporation (formerly Southern Energy, Inc.)
MISSISSIPPI................................... Mississippi Power Company
NRC........................................... Nuclear Regulatory Commission
OPC........................................... Oglethorpe Power Corporation
operating companies........................... ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
PPA........................................... Purchased Power Agreements
PSC........................................... Public Service Commission
RFP........................................... Request for Proposal
RTO........................................... Regional Transmission Organization
RUS........................................... Rural Utility Service (formerly Rural Electrification
Administration)
ii
DEFINITIONS
(continued)
SAVANNAH...................................... Savannah Electric and Power Company
SCS........................................... Southern Company Services, Inc. (the system
service company)
SEC........................................... Securities and Exchange Commission
SEGCO......................................... Southern Electric Generating Company
SEPA.......................................... Southeastern Power Administration
SERC.......................................... Southeastern Electric Reliability Council
SMEPA......................................... South Mississippi Electric Power Association
SOUTHERN...................................... The Southern Company
Southern LINC................................. Southern Communications Services, Inc.
Southern Management Development............... Southern Management Development, Inc.
Southern Nuclear.............................. Southern Nuclear Operating Company, Inc.
Southern Power................................ Southern Power Company
SOUTHERN system............................... SOUTHERN, the operating companies, Southern Power,
SEGCO, Southern Nuclear, SCS, Southern LINC, Energy Solutions
and other subsidiaries
Southern Telecom.............................. Southern Telecom, Inc.
TVA........................................... Tennessee Valley Authority
iii
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking and historical
information. Forward-looking information includes, among other things,
statements concerning the strategic goals for SOUTHERN's new wholesale business
and also SOUTHERN's goals for dividend payout ratio, earnings per share and
earnings growth. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "could," "should," "expects," "plans,"
"anticipates," "believes," "estimates," "projects," "predicts," "potential" or
"continue" or the negative of these terms or other comparable terminology.
SOUTHERN cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which SOUTHERN
and its subsidiaries are subject, as well as changes in application of existing
laws and regulations; current and future litigation, including the pending EPA
civil action against certain SOUTHERN subsidiaries and the race discrimination
litigation against certain SOUTHERN subsidiaries; the effects, extent and timing
of the entry of additional competition in the markets in which SOUTHERN's
subsidiaries operate; the impact of fluctuations in commodity prices, interest
rates and customer demand; state and federal rate regulations; political, legal
and economic conditions and developments in the United States; the performance
of projects undertaken by the non-traditional business and the success of
efforts to invest in and develop new opportunities; internal restructuring or
other restructuring options that may be pursued; potential business strategies,
including acquisitions or dispositions of assets or businesses, which cannot be
assured to be completed or beneficial to SOUTHERN or its subsidiaries; the
effects of, and changes in, economic conditions in the areas in which SOUTHERN's
subsidiaries operate; the direct or indirect effects on SOUTHERN's business
resulting from the terrorist incidents on September 11, 2001, or any similar
such incidents or responses to such incidents; financial market conditions and
the results of financing efforts; the timing and acceptance of SOUTHERN's new
product and service offerings; the ability of SOUTHERN to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports filed from
time to time with the SEC.
iv
PART I
Item 1. BUSINESS
SOUTHERN was incorporated under the laws of Delaware on November 9, 1945.
SOUTHERN is domesticated under the laws of Georgia and is qualified to do
business as a foreign corporation under the laws of Alabama. SOUTHERN owns all
the outstanding common stock of ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH, each of which is an operating public utility company. The operating
companies supply electric service in the states of Alabama, Georgia, Florida,
Mississippi and Georgia, respectively. More particular information relating to
each of the operating companies is as follows:
ALABAMA is a corporation organized under the laws of the State of Alabama
on November 10, 1927, by the consolidation of a predecessor Alabama Power
Company, Gulf Electric Company and Houston Power Company. The predecessor
Alabama Power Company had had a continuous existence since its
incorporation in 1906.
GEORGIA was incorporated under the laws of the State of Georgia on June
26, 1930, and admitted to do business in Alabama on September 15, 1948.
GULF is a corporation which was organized under the laws of the State of
Maine on November 2, 1925, and admitted to do business in Florida on
January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on
November 20, 1984.
MISSISSIPPI was incorporated under the laws of the State of Mississippi on
July 12, 1972, was admitted to do business in Alabama on November 28,
1972, and effective December 21, 1972, by the merger into it of the
predecessor Mississippi Power Company, succeeded to the business and
properties of the latter company. The predecessor Mississippi Power
Company was incorporated under the laws of the State of Maine on November
24, 1924, and was admitted to do business in Mississippi on December 23,
1924, and in Alabama on December 7, 1962.
SAVANNAH is a corporation existing under the laws of the State of Georgia;
its charter was granted by the Secretary of State on August 5, 1921.
SOUTHERN also owns all the outstanding common stock of Southern LINC,
Southern Nuclear, SCS, Southern Management Development (formerly Energy
Solutions), Southern Telecom, Southern Power and other direct and indirect
subsidiaries. Southern LINC provides digital wireless communications services to
SOUTHERN's operating companies and also markets these services to the public
within the Southeast. Southern Nuclear provides services to ALABAMA's and
GEORGIA's nuclear plants. Southern Management Development focuses on new and
existing programs to enhance customer satisfaction, efficiency and stockholder
value. Southern Telecom provides wholesale fiber optic solutions to
telecommunication providers in the Southeastern United States.
In January 2001, SOUTHERN formed a new subsidiary, Southern Power. This
subsidiary constructs, owns and manages wholesale generating assets in the
Southeast. Southern Power will be the primary growth engine for SOUTHERN's
competitive wholesale market-based energy business.
ALABAMA and GEORGIA each own 50% of the outstanding common stock of SEGCO.
SEGCO owns electric generating units with an aggregate capacity of 1,019,680
kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and
ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and
energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and
furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000
volt transmission lines extending from Plant Gaston to the Georgia state line at
which point connection is made with the GEORGIA transmission line system.
Reference is made to Note 12 to the financial statements of SOUTHERN in Item
8 herein for additional information regarding SOUTHERN's segment and related
information.
Mirant Corporation
In April 2000, SOUTHERN announced an initial public offering of up to 19.9
percent of Mirant and its intentions to spin off the remaining ownership of
Mirant to SOUTHERN stockholders within 12 months of the initial stock offering.
On October 2, 2000, Mirant completed its initial public offering of 66.7 million
I-1
shares of common stock priced at $22 per share. This represented 19.7 percent of
the 338.7 million shares outstanding. As a result of the stock offering,
SOUTHERN recorded a $560 million increase in paid-in capital with no gain or
loss being recognized.
On February 19, 2001, SOUTHERN's board of directors approved the spin off of
its remaining ownership of 272 million Mirant shares. On April 2, 2001, the
tax-free distribution of Mirant shares was completed at a ratio of approximately
0.4 for every share of SOUTHERN common stock held at record date.
The distribution resulted in charges of approximately $3.2 billion and $0.4
billion to SOUTHERN's paid-in capital and retained earnings, respectively.
As a result of the spin off, SOUTHERN's financial statements reflect Mirant's
results of operations, balance sheets and cash flows as discontinued operations.
The SOUTHERN System
Operating Companies
The transmission facilities of each of the operating companies are connected to
the respective company's own generating plants and other sources of power and
are interconnected with the transmission facilities of the other operating
companies and SEGCO by means of heavy-duty high voltage lines. (In the case of
GEORGIA's integrated transmission system, see Item 1 - BUSINESS - "Territory
Served by the Operating Companies" herein.)
Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the operating companies have entered into voluntary reliability
agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy
Corporation, South Carolina Electric & Gas Company and Virginia Electric and
Power Company, each of which provides for the establishment and periodic review
of principles and procedures for planning and operation of generation and
transmission facilities, maintenance schedules, load retention programs,
emergency operations and other matters affecting the reliability of bulk power
supply. The operating companies have joined with other utilities in the
Southeast (including those referred to above) to form the SERC to augment
further the reliability and adequacy of bulk power supply. Through the SERC, the
operating companies are represented on the National Electric Reliability
Council.
An intra-system interchange agreement provides for coordinating operations
of the power producing facilities of the operating companies and the capacities
available to such companies from non-affiliated sources and for the pooling of
surplus energy available for interchange. Coordinated operation of the entire
interconnected system is conducted through a central power supply coordination
office maintained by SCS. The available sources of energy are allocated to the
operating companies to provide the most economical sources of power consistent
with good operation. The resulting benefits and savings are apportioned among
the operating companies.
SCS has contracted with SOUTHERN, each operating company, various of the
other subsidiaries, Southern Nuclear, Southern Power and SEGCO to furnish, at
cost and upon request, the following services: general executive and advisory
services, power pool operations, general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pensions, corporate, rates, budgeting, public
relations, human resources, systems and procedures and other services with
respect to business and operations and power pool operations. Southern
Management Development and Southern LINC have also secured from the operating
companies certain services which are furnished at cost.
Southern Nuclear has contracts with ALABAMA to operate the Farley Nuclear
Plant, and with GEORGIA to operate Plants Hatch and Vogtle. See Item 1 -
BUSINESS - "Regulation - Atomic Energy Act of 1954" herein.
Southern Power
As stated above, Southern Power will be the primary growth engine for SOUTHERN's
competitive wholesale market-based energy business. Southern Power intends to
sell the output of its generating assets under long-term, market-based contracts
I-2
both to unaffiliated wholesale purchasers as well as the operating companies
(under power purchase agreements approved by the respective public service
commissions). Southern Power's wholesale generating assets will not be placed in
the operating companies' rate bases, and Southern Power will only be able to
recover costs from the operating companies based on the terms of the
market-based contracts for its wholesale generating assets. The market-based
contracts typically pass the cost of fuel to the wholesale energy purchasers and
reduce Southern Power's business risks, but its overall profit will depend on
the parameters of the wholesale market and its efficient operation of its
wholesale generating assets. By the end of 2003, Southern Power plans to have
approximately 4,700 megawatts of generating capacity in commercial operation. At
December 31, 2001, 800 megawatts were in commercial operation and some 3,900
megawatts of capacity are under construction.
Other Business
In March 2001, Energy Solutions changed its name to Southern Management
Development. Southern Management Development then created a separate entity,
Southern Company Energy Solutions LLC (SCES LLC) for its energy business. SCES
LLC provides energy related services such as energy outsourcing, energy
conservation, facility maintenance, energy management and turnkey services for
industrial, commercial, and governmental customers. Southern Management
Development focuses on new and existing programs to enhance customer
satisfaction, efficiency and stockholder value. Examples are: Bill Payment
Protection, an insurance product that protects a residential customer by paying
the electric bill in the event the customer becomes involuntarily unemployed,
disabled or goes on unpaid leave; and Electric Vehicle Chargers, a program to
supply electric vehicle charging units to industrial customers.
In 1996, Southern LINC began serving SOUTHERN's operating companies and
marketing its services to non-affiliates within the Southeast. Its system covers
approximately 127,000 square miles and combines the functions of two-way radio
dispatch, cellular phone, short text and numeric messaging and wireless data
transfer.
These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations. However, these activities also involve a higher degree of risk.
SOUTHERN expects to make substantial investments over the period 2002-2004 in
these and other new businesses.
In 1999, MESH, a subsidiary of SOUTHERN, filed a petition for Chapter 11
bankruptcy relief in the U.S. Bankruptcy Court. On August 4, 2000, MESH filed a
proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed
plan of reorganization was most recently amended on October 15, 2001. SOUTHERN
expects that approval of a plan of reorganization would result in either a
termination of SOUTHERN's ownership interest in MESH or the exchange of all
assets of MESH for the cancellation of securities held by the bondholders, but
would not affect SOUTHERN's continuing guarantee obligations. Reference is made
to Item 3 - "Legal Proceedings" herein for additional information relating to
this matter.
Certain Factors Affecting the Industry
Various factors are currently affecting the electric utility industry in
general, including increasing competition and the regulatory changes related
thereto, costs required to comply with environmental regulations and the
potential for new business opportunities (with their associated risks) outside
of traditional rate-regulated operations. The effects of these and other factors
on the SOUTHERN system are described herein. Particular reference is made to
Item 1 - BUSINESS - "Other Business", "Competition" and "Environmental
Regulation." See also "Cautionary Statement Regarding Forward-Looking
Information."
In December 1999, the FERC issued its final rule on RTOs. The order
encouraged utilities owning transmission systems to form RTOs on a voluntary
basis. SOUTHERN has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
SOUTHERN explained that it is developing a for-profit RTO known as SeTrans with
a number of non-jurisdictional cooperative and public power entities. Recently,
Entergy Corporation and Cleco Power joined the SeTrans development process. In
January 2002, the sponsors of SeTrans held a public meeting to form a
I-3
Stakeholder Advisory Committee, which will participate in the development of the
RTO. SOUTHERN continues to work with the other sponsors to develop the SeTrans
RTO. The creation of SeTrans is not expected to have a material impact on
SOUTHERN's financial statements. The outcome of this matter cannot now be
determined.
Construction Programs
The subsidiary companies of SOUTHERN are engaged in continuous construction
programs to accommodate existing and estimated future loads on their respective
systems. Construction additions or acquisitions of property during 2002 through
2004 by the operating companies, SEGCO, SCS, Southern LINC, Southern Power and
other subsidiaries are estimated as follows: (in millions)
------------------------------ -------- --------- ----------
2002 2003 2004
-------- --------- ----------
ALABAMA $ 671 $ 592 $673
GEORGIA 971 752 809
GULF 103 72 107
MISSISSIPPI 84 72 85
SAVANNAH 35 38 43
SEGCO 15 17 23
SCS 27 23 25
Southern LINC 29 28 23
Southern Power 834 488 473
Other 29 14 2
--------------------------- ----------- --------- ----------
SOUTHERN system $2,798 $2,096 $ 2,263
=========================== =========== ========= ==========
I-4
Estimated construction costs in 2002 are expected to be apportioned approximately as follows: (in millions)
---------------------------- --------------- --------------- ------------- --------- --------------- ---------------- ------------
SOUTHERN Southern
system* ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH Power
--------------- --------------- ------------- --------- --------------- ---------------- ------------
New generation $ 833 $ - $ - $24 $- $- $809
Other generating
facilities including
associated plant
substations 703 248 383 24 25 8 -
New business 365 127 182 23 15 18 -
Transmission 378 141 210 9 16 2 -
Joint line and substation 55 - 45 7 3 - -
Distribution 162 68 61 10 17 6 -
Nuclear fuel 123 63 60 - - - -
General plant 179 24 30 6 8 1 25
--------------- --------------- ------------- --------- --------------- ---------------- ------------
$2,798 $671 $971 $103 $84 $35 $834
=============== =============== ============= ========= =============== ================ ============
* SCS, Southern LINC and other businesses plan capital additions to general
plant in 2002 of $27 million, $29 million and $29 million, respectively, while
SEGCO plans capital additions of $15 million to generating facilities. (See Item
1 - BUSINESS - "Other Business" herein.)
The construction programs are subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include: changes in business conditions; acquisitions of
additional generating assets; revised load growth estimates; changes in
environmental regulations; changes in existing nuclear plants to meet new
regulatory requirements; increasing costs of labor, equipment and materials; and
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered.
SOUTHERN has approximately 4,500 megawatts of new generating capacity
scheduled to be placed in service by 2003. Approximately 3,900 megawatts of
additional new capacity will be dedicated to the wholesale market and owned by
Southern Power. Significant construction of transmission and distribution
facilities and upgrading of generating plants will be continuing.
Under Georgia law, GEORGIA and SAVANNAH each are required to file an
Integrated Resource Plan for approval by the Georgia PSC. Under the plan rules,
the Georgia PSC must pre-certify the construction of new power plants and new
purchase power contracts. (See Item 1 - BUSINESS - "Rate Matters - Integrated
Resource Planning" herein.)
See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein for
information with respect to certain existing and proposed environmental
requirements and Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein for
additional information concerning ALABAMA's, GEORGIA's and Southern Power's
joint ownership of certain generating units and related facilities with certain
non-affiliated utilities.
I-5
Financing Programs
The amount and timing of additional equity capital to be raised in 2002, as well
as in subsequent years, will be contingent on SOUTHERN's investment
opportunities. Equity capital can be provided from any combination of public
offerings, private placements or SOUTHERN's stock plans.
The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources and by the issuances of new debt and preferred
equity securities, term loans and short-term borrowings. However, the type and
timing of any financings -- if needed -- will depend on market conditions and
regulatory approval. In recent years, financings primarily have utilized
unsecured debt and trust preferred securities.
Southern Power will use both external funds and equity capital from SOUTHERN
to finance its construction program. In addition, Southern Power has an $850
million revolving credit facility which extends through November 2004.
Short-term debt is often utilized as appropriate at SOUTHERN, the operating
companies, SEGCO and Southern Power.
The maximum amounts of short-term and term-loan indebtedness authorized by
the appropriate regulatory authorities are shown on the following table:
Amount Outstanding at
Authorized December 31, 2001
-------------- ---------------------
(in millions)
ALABAMA $1,000(1) $ 10
GEORGIA 1,700(2) 748
GULF 300(1) 87
MISSISSIPPI 350(1) 16
SAVANNAH 205(2) 32
Southern Power 2,500(3) 1
SOUTHERN 2,000(1) 950
------------------- ------------- -- -------------------
Notes:
(1) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 2003. No SEC authorization is required for
ALABAMA. GULF, MISSISSIPPI and SOUTHERN have received SEC authorization to issue
from time to time short-term and/or term-loan notes to banks and commercial
paper to dealers in the amounts shown through December 31, 2003, December 31,
2002 and December 31, 2004, respectively.
(2) GEORGIA and SAVANNAH have received SEC authorization to issue from time
to time short-term and term-loan notes to banks and commercial paper to dealers
in the amounts shown through December 31, 2002. Authorization for term-loan
indebtedness is also required by the Georgia PSC. SAVANNAH received authority
from the Georgia PSC for $115 million in term loans expiring December 31, 2003.
As a part of a financing request from the Georgia PSC, GEORGIA has asked for
financing authority of $1.765 billion in term loans.
(3) Southern Power has been authorized by the SEC to enter into various
financing arrangements, including short-term loans, through June 30, 2005, which
in the aggregate may not exceed $2.5 billion.
Reference is made to Note 8 to the financial statements for SOUTHERN, Note 8
to the financial statements for ALABAMA, GULF and MISSISSIPPI and Note 6 to the
financial statements for SAVANNAH and Note 9 to the financial statements for
GEORGIA in Item 8 herein for information regarding the registrants' bank credit
arrangements.
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Fuel Supply
The operating companies' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1999 through
2001 are shown below:
Oil and
ALABAMA Coal Nuclear Hydro Gas
--------- ---------- --------- ---------
1999 72 20 5 3
2000 72 19 3 6
2001 64 18 6 12
GEORGIA
1999 75 22 1 2
2000 76 21 1 2
2001 75 23 1 1
GULF
1999 97 ** ** 3
2000 98 ** ** 2
2001 99 ** ** 1
MISSISSIPPI
1999 81 ** ** 19
2000 83 ** ** 17
**
2001 59 ** ** 41
SAVANNAH
1999 78 ** ** 22
2000 88 ** ** 12
2001 93 ** ** 7
SEGCO
1999 100 ** ** *
2000 100 ** ** *
2001 100 ** ** *
SOUTHERN system***
1999 78 17 2 3
2000 78 16 2 4
2001 72 16 3 9
---------- ------- --------- ---------- --------- ---------
*Less than 0.5%.
**Not applicable.
*** Amounts shown for the SOUTHERN system are weighted averages of the
operating companies, Southern Power and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 1999
through 2001 are shown below:
1999 2000 2001
-------------- ------------- -------------
ALABAMA 1.44 1.54 1.56
GEORGIA 1.34 1.39 1.38
GULF 1.60 1.68 1.76
MISSISSIPPI 1.65 1.80 1.89
SAVANNAH 2.20 2.28 2.16
SEGCO 1.77 1.51 1.44
SOUTHERN
System* 1.45 1.51 1.56
- ------------------- -------------- ------------- -------------
* Amounts shown for the SOUTHERN system are weighted averages of the operating
companies, Southern Power and SEGCO.
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The operating companies have long-term agreements in place from which they
expect to receive approximately 78% of their coal burn requirements in 2002.
These agreements cover remaining terms up to 9 years. In 2001, the weighted
average sulfur content of all coal burned by the operating companies was 0.76%
sulfur. This sulfur level, along with banked sulfur dioxide allowances, allowed
the operating companies to remain within limits as set forth by Phase II of the
Clear Air Act. As more and more strict environmental regulations are proposed
that impact the utilization of coal, the fuel mix will be monitored to insure
that sufficient quantities of the proper type of coal or natural gas are in
place to remain in compliance with applicable laws and regulations. See Item 1 -
BUSINESS - "Regulation - Environmental Regulation" herein.
The operating companies and Southern Power also have long-term agreements in
place for their natural gas burn requirements. For 2002, the operating companies
and Southern Power have contracted for 163.6 billion cubic feet of natural gas
supply. These agreements cover remaining terms up to 5 years. In addition to gas
supply, the operating companies have contracts in place for both firm gas
transportation and firm gas storage. Management believes that these contracts
provide sufficient natural gas supplies, transportation and storage to ensure
normal operations of the SOUTHERN system's natural gas generating units.
Changes in fuel prices are generally reflected in fuel adjustment clauses
contained in rate schedules. See Item 1 - BUSINESS - "Rate Matters - Rate
Structure" herein.
ALABAMA and GEORGIA have numerous contracts covering a portion of their
nuclear fuel needs for uranium, conversion services, enrichment services and
fuel fabrication. These contracts have varying expiration dates and most are
short to medium term (less than 10 years). Management believes that sufficient
capacity for nuclear fuel supplies and processing exists to preclude the
impairment of normal operations of the SOUTHERN system's nuclear generating
units.
ALABAMA and GEORGIA have contracts with the DOE that provide for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent fuel in January 1998, as required by the contracts, and the companies are
pursuing legal remedies against the government for breach of contract.
Sufficient pool storage capacity is available at Plant Farley to maintain
full-core discharge capability until the refueling outages scheduled for 2006
and 2008 for units 1 & 2, respectively. Sufficient pool storage capacity
currently for spent fuel is available at Plant Vogtle to maintain full-core
discharge capability for both units into 2014. To maintain pool discharge
capability at Plant Hatch, effective June 2000, an on-site dry storage facility
became operational. Sufficient dry storage capacity is believed to be available
to continue dry storage operations at Plant Hatch through the life of the plant.
Procurement of on-site dry storage capacity at Plant Vogtle will begin in
sufficient time to maintain pool full-core discharge capability.
The Energy Act 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, including ALABAMA and GEORGIA. This
assessment is being paid over a 15-year period which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will recover
these payments in the same manner as any other fuel expense.
Territory Served by the Operating Companies
The territory in which the operating companies provide electric service
comprises most of the states of Alabama and Georgia together with the
northwestern portion of Florida and southeastern Mississippi. In this territory
there are non-affiliated electric distribution systems which obtain some or all
of their power requirements either directly or indirectly from the operating
companies. The territory has an area of approximately 120,000 square miles and
an estimated population of approximately 11 million.
ALABAMA is engaged, within the State of Alabama, in the generation and
purchase of electricity and the distribution and sale of such electricity at
retail in over 1,000 communities (including Anniston, Birmingham, Gadsden,
Mobile, Montgomery and Tuscaloosa) and at wholesale to 15 municipally-owned
electric distribution systems, 11 of which are served indirectly through sales
to AMEA, and two rural distributing cooperative associations. ALABAMA also
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supplies steam service in downtown Birmingham. ALABAMA also sells, and
cooperates with dealers in promoting the sale of, electric appliances.
GEORGIA is engaged in the generation and purchase of electricity and the
distribution and sale of such electricity within the State of Georgia at retail
in over 600 communities, as well as in rural areas, and at wholesale currently
to OPC, MEAG, Dalton and the City of Hampton.
GULF is engaged, within the northwestern portion of Florida, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail in 71 communities (including Pensacola, Panama City and
Fort Walton Beach), as well as in rural areas, and at wholesale to a
non-affiliated utility and a municipality.
MISSISSIPPI is engaged in the generation and purchase of electricity and the
distribution and sale of such energy within the 23 counties of southeastern
Mississippi, at retail in 123 communities (including Biloxi, Gulfport,
Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and at
wholesale to one municipality, six rural electric distribution cooperative
associations and one generating and transmitting cooperative.
SAVANNAH is engaged, within a five-county area in eastern Georgia, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail and, as a member of the SOUTHERN system power pool, the
transmission and sale of wholesale energy.
For information relating to kilowatt-hour sales by classification for each
registrant, reference is made to "Management's Discussion and Analysis-Results
of Operations" in Item 7 herein. Also, for information relating to the sources
of revenues for the SOUTHERN system and each of the operating companies,
reference is made to Item 6 herein.
A portion of the area served by the operating companies adjoins the area
served by TVA and its municipal and cooperative distributors. An Act of Congress
limits the distribution of TVA power, unless otherwise authorized by Congress,
to specified areas or customers which generally were those served on July 1,
1957.
The RUS has authority to make loans to cooperative associations or
corporations to enable them to provide electric service to customers in rural
sections of the country. There are 71 electric cooperative organizations
operating in the territory in which the operating companies provide electric
service at retail or wholesale.
One of these, AEC, is a generating and transmitting cooperative selling
power to several distributing cooperatives, municipal systems and other
customers in south Alabama and northwest Florida. AEC owns generating units with
approximately 840 megawatts of nameplate capacity, including an undivided
ownership interest in ALABAMA's Plant Miller Units 1 and 2. AEC's facilities
were financed with RUS loans secured by long-term contracts requiring
distributing cooperatives to take their requirements from AEC to the extent such
energy is available. Two of the 14 distributing cooperatives operating in
ALABAMA's service territory obtain a portion of their power requirements
directly from ALABAMA.
Four electric cooperative associations, financed by the RUS, operate within
GULF's service area. These cooperatives purchase their full requirements from
AEC and SEPA (a federal power marketing agency). A non-affiliated utility also
operates within GULF's service area and purchases its full requirements from
GULF.
ALABAMA and GULF have entered into separate agreements with AEC involving
interconnection between the respective systems. The delivery of capacity and
energy from AEC to certain distributing cooperatives in the service areas of
ALABAMA and GULF is governed by the SOUTHERN/AEC Network Transmission Service
Agreement. The rates for this service to AEC are based on the negotiated
agreement on file with the FERC. See Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein for details of ALABAMA's joint-ownership with AEC of a
portion of Plant Miller.
MISSISSIPPI has an interchange agreement with SMEPA, a generating and
transmitting cooperative, pursuant to which various services are provided,
including the furnishing of protective capacity by MISSISSIPPI to SMEPA. SMEPA
has a generating capacity of 1,947 megawatts and a transmission system estimated
to be 1,549 miles in length.
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There are 43 electric cooperative organizations operating in, or in areas
adjoining, territory in the State of Georgia in which GEORGIA provides electric
service at retail or wholesale. Three of these organizations obtain their power
from TVA and one from other sources. OPC has a wholesale power contract with the
remaining 39 of these cooperative organizations. OPC utilizes self-owned
generation acquired from GEORGIA, megawatt capacity purchases from GEORGIA under
power supply agreements, and other arrangements to meet its power supply
obligations. Pursuant to the latest agreement entered into in April 1999, OPC
will purchase 250 megawatts of steam capacity through March 2006.
There are 65 municipally-owned electric distribution systems operating in
the territory in which the operating companies provide electric service at
retail or wholesale.
AMEA was organized under an act of the Alabama legislature and is comprised
of 11 municipalities. In 1986, ALABAMA entered into a firm power sales contract
with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum of 100
megawatts) for a period of 15 years (1986 Contract). In October 1991, ALABAMA
entered into a second firm power purchase contract with AMEA entitling AMEA to
scheduled amounts of additional capacity (to a maximum 80 megawatts) for a
period of 15 years (1991 Contract). Under the terms of the contracts, ALABAMA
received payments from AMEA representing the net present value of the revenues
associated with the respective capacity entitlements. The 1986 Contract expired
in July 2001, however, the payments for the 1991 Contract will continue as
scheduled capacity is made available over the terms of the 1991 Contract. See
Note 6 to ALABAMA's financial statements in Item 8 herein for further
information on these contracts.
Forty-eight municipally-owned electric distribution systems and one
county-owned system receive their requirements through MEAG, which was
established by a state statute in 1975. MEAG serves these requirements from
self-owned generation facilities acquired from GEORGIA, power purchased from
GEORGIA and purchases from other resources. In August 1997, a pseudo scheduling
and services agreement was implemented between GEORGIA and MEAG that replaced
the partial requirements tariff pursuant to which GEORGIA previously sold
wholesale energy to MEAG. Since 1977, Dalton has filled its requirements from
self-owned generation facilities acquired from GEORGIA and through purchases
from GEORGIA pursuant to their partial requirements tariff. One
municipally-owned electric distribution system's full requirements are served
under a market-based contract by GEORGIA. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.)
GEORGIA has entered into substantially similar agreements with Georgia
Transmission Corporation (formerly OPC's transmission division), MEAG and Dalton
providing for the establishment of an integrated transmission system to carry
the power and energy of each. The agreements require an investment by each party
in the integrated transmission system in proportion to its respective share of
the aggregate system load. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities"
herein.)
SCS, acting on behalf of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH,
also has a contract with SEPA providing for the use of those companies'
facilities at government expense to deliver to certain cooperatives and
municipalities, entitled by federal statute to preference in the purchase of
power from SEPA, quantities of power equivalent to the amounts of power
allocated to them by SEPA from certain United States government hydroelectric
projects.
The retail service rights of all electric suppliers in the State of Georgia
are regulated by the 1973 State Territorial Electric Service Act. Pursuant to
the provisions of this Act, all areas within existing municipal limits were
assigned to the primary electric supplier therein on March 29, 1973 (451
municipalities, including Atlanta, Columbus, Macon, Augusta, Athens, Rome and
Valdosta, to GEORGIA; 115 to electric cooperatives; and 50 to publicly-owned
systems). Areas outside of such municipal limits were either to be assigned or
to be declared open for customer choice of supplier by action of the Georgia PSC
pursuant to standards set forth in the Act. Consistent with such standards, the
Georgia PSC has assigned substantially all of the land area in the state to a
supplier. Notwithstanding such assignments, the Act provides that any new
customer locating outside of 1973 municipal limits and having a connected load
of at least 900 kilowatts may receive electric service from the supplier of its
choice. (See also Item 1 - BUSINESS - "Competition" herein.)
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Under and subject to the provisions of its franchises and concessions and
the 1973 State Territorial Electric Service Act, SAVANNAH has the full but
nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale,
Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee
Island, Springfield, Thunderbolt and Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been
assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and
Screven Counties by the Georgia PSC. (See also Item 1 - BUSINESS - "Competition"
herein.)
Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather
Certificates" of public convenience and necessity to MISSISSIPPI and to six
distribution rural cooperatives operating in southeastern Mississippi, then
served in whole or in part by MISSISSIPPI, authorizing them to distribute
electricity in certain specified geographically described areas of the state.
The six cooperatives serve approximately 300,000 retail customers in a
certificated area of approximately 10,300 square miles. In areas included in a
"Grandfather Certificate," the utility holding such certificate may, without
further certification, extend its lines up to five miles; other extensions
within that area by such utility, or by other utilities, may not be made except
upon a showing of, and a grant of a certificate of, public convenience and
necessity. Areas included in such a certificate which are subsequently annexed
to municipalities may continue to be served by the holder of the certificate,
irrespective of whether it has a franchise in the annexing municipality. On the
other hand, the holder of the municipal franchise may not extend service into
such newly annexed area without authorization by the Mississippi PSC.
Long-Term Power Sales and Lease Agreements
The operating companies have long-term contractual agreements for the sale and
lease of capacity to certain non-affiliated utilities located outside the
SOUTHERN system service area. These agreements are firm and related to specific
generating units. Because the energy is generally provided at cost under these
agreements, profitability is primarily affected by capacity revenues.
Unit power from specific generating plants is currently being sold to FP&L,
FPC and JEA. Under these agreements, approximately 1,500 megawatts of capacity
is scheduled to be sold annually unless reduced by FP&L, FPC and JEA for the
periods after 2001 with a minimum of three years notice, until the expiration of
the contracts in 2010.
Southern Power and MISSISSIPPI have operating leases for portions of their
generating unit capacity.
Reference is made to Note 5 to the financial statements for SOUTHERN; Note 6
to the financial statements for ALABAMA, GULF and MISSISSIPPI and Note 7 to the
financial statements for GEORGIA in Item 8 herein for additional information
regarding contracts for the sales and lease of capacity and energy to
non-territorial customers.
Competition
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Act. The Energy Act allows 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 commercial customers and sell energy generation to other
utilities. Also, electricity sales for resale rates are affected by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.
Although the Energy Act does not permit retail customer access, it has been
a major catalyst for the recent restructuring and consolidations taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages that promote wholesale and retail competition. Among other
things, these initiatives allow customers to choose their electricity provider.
Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been discussed in Alabama,
Florida, Georgia and Mississippi, none have been enacted. Enactment would
require numerous issues to be resolved, including significant ones relating to
recovery of any stranded investments, full cost recovery of energy produced and
I-11
other issues related to the energy crisis that occurred in California. As a
result of that crisis, many states have either discontinued or delayed
implementation of initiatives involving retail deregulation.
Reference is made to Item 1 - BUSINESS - "Certain Factors Affecting the
Industry" herein for information relating to SOUTHERN's RTO filing with the
FERC.
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 SOUTHERN's electric utilities do not remain low-cost
producers and provide quality service, then energy sales growth could be
limited, and this could significantly erode earnings. Reference is made to
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, "Management's Discussion and
Analysis - Future Earnings Potential" in Item 7 herein for further discussion of
rate matters.
To adapt to a less regulated, more competitive environment, SOUTHERN
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets or some combination thereof.
Furthermore, SOUTHERN may engage in new business ventures that arise from
competitive and regulatory changes in the utility industry. Pursuit of any of
the above strategies, or any combination thereof, may significantly affect the
business operations and financial condition of SOUTHERN. (See Item 1 - BUSINESS
- - "Southern Power" and "Other Business" herein.)
As a result of the foregoing factors, SOUTHERN has experienced increasing
competition for available off-system sales of capacity and energy from
neighboring utilities and alternative sources of energy. Additionally, the
future effect of cogeneration and small-power production facilities on the
SOUTHERN system cannot currently be determined but may be adverse.
SOUTHERN is working to maintain and expand its share of wholesale energy
sales in the Southeastern power markets. In January 2001, SOUTHERN formed a new
subsidiary - Southern Power. This subsidiary constructs, owns and manages
wholesale generating assets in the Southeast. Southern Power will be the primary
growth engine for SOUTHERN's competitive wholesale market-based energy business.
By the end of 2003, Southern Power plans to have approximately 4,700 megawatts
of generating capacity in commercial operation. At December 31, 2001, 800
megawatts were in commercial operation and some 3,900 megawatts of capacity are
under construction.
ALABAMA currently has cogeneration contracts in effect with 10 industrial
customers. Under the terms of these contracts, ALABAMA purchases excess
generation of such companies. During 2001, ALABAMA purchased approximately 154
million kilowatt-hours from such companies at a cost of $5.5 million.
GEORGIA currently has contracts in effect with nine small power producers
whereby GEORGIA purchases their excess generation. During 2001, GEORGIA
purchased 13.6 million kilowatt-hours from such companies at a cost of $355,000.
GEORGIA has purchased power agreements for electricity with two cogeneration
facilities. Payments are subject to reductions for failure to meet minimum
capacity output. During 2001, GEORGIA purchased 621.7 million kilowatt-hours at
a cost of $52.3 million from these facilities. Reference is made to Note 4 to
the financial statements for GEORGIA in Item 8 herein for information regarding
purchased power commitments.
GULF currently has agreements in effect with four industrial customers
pursuant to which GULF purchases "as available" energy from customer-owned
generation. During 2001, GULF purchased 114 million kilowatt-hours from such
companies for $3.4 million.
SAVANNAH currently has cogeneration contracts in effect with four large
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 2001, SAVANNAH purchased 41.2 million
kilowatt-hours from such companies at a cost of $1.4 million.
The competition for retail energy sales among competing suppliers of energy
is influenced by various factors, including price, availability, technological
advancements and reliability. These factors are, in turn, affected by, among
other influences, regulatory, political and environmental considerations,
taxation and supply.
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The operating companies have experienced, and expect to continue to
experience, competition in their respective retail service territories in
varying degrees as the result of self-generation (as described above) and fuel
switching by customers and other factors. (See also Item 1 - BUSINESS -
"Territory Served by the Operating Companies" herein for information concerning
suppliers of electricity operating within or near the areas served at retail by
the operating companies.)
Regulation
State Commissions
The operating companies are subject to the jurisdiction of their respective
state regulatory commissions, which have broad powers of supervision and
regulation over public utilities operating in the respective states, including
their rates, service regulations, sales of securities (except for the
Mississippi PSC) and, in the cases of the Georgia PSC and Mississippi PSC, in
part, retail service territories. (See Item 1 - BUSINESS - "Rate Matters" and
"Territory Served by the Operating Companies" herein.)
Holding Company Act
SOUTHERN is registered as a holding company under the Holding Company Act, and
it and its subsidiary companies are subject to the regulatory provisions of said
Act, including provisions relating to the issuance of securities, sales and
acquisitions of securities and utility assets, services performed by SCS and
Southern Nuclear and the activities of certain of SOUTHERN's other subsidiaries.
While various proposals have been introduced in Congress regarding the
Holding Company Act, the prospects for legislative reform or repeal are
uncertain at this time.
Federal Power Act
The Federal Power Act subjects the operating companies, Southern Power and SEGCO
to regulation by the FERC as companies engaged in the transmission or sale at
wholesale of electric energy in interstate commerce, including regulation of
accounting policies and practices.
ALABAMA and GEORGIA are also subject to the provisions of the Federal Power
Act or the earlier Federal Water Power Act applicable to licensees with respect
to their hydroelectric developments. Among the hydroelectric projects subject to
licensing by the FERC are 14 existing ALABAMA generating stations having an
aggregate installed capacity of 1,593,600 kilowatts and 18 existing GEORGIA
generating stations having an aggregate installed capacity of 1,074,696
kilowatts.
GEORGIA started the relicensing process for the Middle Chattahoochee
Project in 1998. This project consists of the Goat Rock, Oliver and North
Highlands facilities.
GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity
which began commercial operation in 1995. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.)
Licenses for all projects, excluding those discussed above, expire in the
period 2007-2033 in the case of ALABAMA's projects and in the period 2005-2039
in the case of GEORGIA's projects.
Upon or after the expiration of each license, the United States Government,
by act of Congress, may take over the project or the FERC may relicense the
project either to the original licensee or to a new licensee. In the event of
takeover or relicensing to another, the original licensee is to be compensated
in accordance with the provisions of the Federal Power Act, such compensation to
reflect the net investment of the licensee in the project, not in excess of the
fair value of the property taken, plus reasonable damages to other property of
the licensee resulting from the severance therefrom of the property taken.
Atomic Energy Act of 1954
ALABAMA, GEORGIA and Southern Nuclear are subject to the provisions of the
Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over
the construction and operation of nuclear reactors, particularly with regard to
certain public health and safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a facility licensed under the Atomic
Energy Act of 1954, as amended.
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NRC operating licenses currently expire in June 2017 and March 2021 for
Plant Farley units 1 and 2, respectively, and in January 2027 and February 2029
for Plant Vogtle units 1 and 2, respectively. In January 2002, the NRC granted
GEORGIA a 20-year extension of the licenses for both units at Plant Hatch which
permits the operation of units 1 and 2 until 2034 and 2038, respectively.
Reference is made to Notes 1 and 10 to
SOUTHERN's financial statements, Notes 1 and 9 to ALABAMA's financial statements
and Notes 1 and 5 to GEORGIA's financial statements in Item 8 herein for
information on nuclear decommissioning costs and nuclear insurance.
Additionally, Note 3 to GEORGIA's financial statements contains information
regarding nuclear performance standards imposed by the Georgia PSC that may
impact retail rates.
Environmental Regulation
The operating companies' and SEGCO's operations are subject to federal, state
and local environmental requirements which, among other things, control
emissions of particulates, sulfur dioxide and nitrogen oxides into the air; the
use, transportation, storage and disposal of hazardous and toxic waste; and
discharges of pollutants, including thermal discharges, into waters of the
United States. The operating companies and SEGCO expect to comply with such
requirements, which generally are becoming increasingly stringent, through
technical improvements, the use of appropriate combinations of low-sulfur fuel
and chemicals, addition of environmental control facilities, changes in control
techniques and reduction of the operating levels of generating facilities.
Failure to comply with such requirements could result in the complete shutdown
of individual facilities not in compliance as well as the imposition of civil
and criminal penalties.
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 SOUTHERN. Reductions in sulfur dioxide and nitrogen oxide emissions
from fossil-fired generating plants were required in two phases. Phase I
compliance began in 1995. SOUTHERN achieved Phase I compliance at its affected
plants by primarily switching to low-sulfur coal and with some equipment
upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur
dioxide emissions compliance totaled approximately $300 million. Phase II sulfur
dioxide compliance was required in 2000. SOUTHERN used emission allowances and
fuel switching to comply with Phase II requirements. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits and ozone non-attainment requirements for
metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone
non-attainment requirements increased total construction expenditures through
2000 by approximately $100 million.
Respective state plans to address the one-hour ozone non-attainment
standards for the Atlanta and Birmingham areas have been established and must be
implemented in May 2003. Seven generating plants in the Atlanta area and two
plants in the Birmingham area will be affected. Construction expenditures for
compliance with these new rules are currently estimated at approximately $940
million, of which $520 million remains to be spent.
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provision. 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 made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA. In addition, the Federal District of
Columbia Circuit Court of Appeals is considering other legal challenges to these
standards. A court decision is expected in the spring of 2002. If the standards
are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rule affects 21 states, including
Alabama and Georgia. Compliance is required by May 31, 2004, for most states,
including Alabama. For Georgia, further rulemaking was required, and proposed
I-14
compliance was delayed until May 1, 2005. Additional construction expenditures
for compliance with these new rules are currently estimated at approximately
$190 million.
In December 2000, having completed its utility studies for mercury and
other hazardous air pollutants (HAPS), the EPA issued a determination that an
emission control program for mercury and, perhaps, other HAPS is warranted. The
program is being developed under the Maximum Achievable Control Technology
provisions of the Clear Air Act, and the regulations are scheduled to be
finalized by the end of 2004 with implementation to take place around 2007. In
January 2001, the EPA proposed guidance for the determination of Best Available
Retrofit Technology (BART) emission controls under the Regional Haze
Regulations. Installation of BART controls is expected to take place around
2010. Litigation of the Regional Haze Regulations, including the BART
provisions, is ongoing in the Federal District of Columbia Circuit Court of
Appeals. A court decision is expected in mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reduction in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emission from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and the utility industry. Generally, this rule affects the operation and
maintenance of electrostatic precipitators and could involve significant
additional ongoing expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
SOUTHERN must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the subsidiaries could incur substantial costs to clean up
properties. The subsidiaries conduct studies to determine the extent of any
required cleanup and have recognized in their respective financial statements
costs to clean up known sites. These costs for SOUTHERN amounted to $1 million
in 2001 and $4 million in both 2000 and 1999. Additional sites may require
environmental remediation for which the subsidiaries may be liable for a portion
or all required cleanup costs.
Several major pieces of environmental legislation are periodically
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 SOUTHERN's operations. The full impact of any
such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect SOUTHERN. 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 a result of
lawsuits alleging damages caused by electromagnetic fields.
Reference is made to each registrant's "Management's Discussion and
Analysis" in Item 7 herein for a discussion of the Clean Air Act and other
environmental legislation and proceedings. Also see Item 3 - "Legal
Proceedings", herein for information about a lawsuit brought on behalf of the
EPA.
The operating companies' and SEGCO's estimated capital expenditures for
environmental quality control
I-15
facilities for the years 2002, 2003 and 2004 are as follows: (in millions)
-----------------------------------------------------------
2002 2003 2004
---------------------------------
ALABAMA $157 $95 $112
GEORGIA 320 93 66
GULF 5 15 26
MISSISSIPPI 4 9 1
SAVANNAH 4 6 2
SEGCO * * *
----------------------------------------------------------
Total $490 $218 $207
===========================================================
* Amounts are less than $1 million.
The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating company and SEGCO has incurred costs for
environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis" in Item 7 herein for
information regarding the registrants' environmental remediation efforts. Also,
see Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
information regarding the identification of sites that may require environmental
remediation by GEORGIA.
The operating companies and SEGCO are unable to predict at this time what
additional steps they may be required to take as a result of the implementation
of existing or future quality control requirements for air, water and hazardous
or toxic materials, but such steps could adversely affect system operations and
result in substantial additional costs.
The outcome of the matters mentioned above under "Regulation" cannot now be
determined, except that these developments may result in delays in obtaining
appropriate licenses for generating facilities, increased construction and
operating costs, or reduced generation, the nature and extent of which, while
not determinable at this time, could be substantial.
Rate Matters
Rate Structure
The rates and service regulations of the operating companies are uniform for
each class of service throughout their respective service areas. Rates for
residential electric service are generally of the block type based upon
kilowatt-hours used and include minimum charges.
Residential and other rates contain separate customer charges. Rates for
commercial service are presently of the block type and, for large customers, the
billing demand is generally used to determine capacity and minimum bill charges.
These large customers' rates are generally based upon usage by the customer
including those with special features to encourage off-peak usage. Additionally,
the operating companies are allowed by their respective PSCs to negotiate the
terms and compensation of service to large customers. Such terms and
compensation of service, however, are subject to final PSC approval. ALABAMA,
GEORGIA and SAVANNAH are allowed by state law to recover fuel and net purchased
energy costs through fuel cost recovery provisions which are adjusted to reflect
increases or decreases in such costs. GULF recovers from retail customers costs
of fuel, net purchased power, energy conservation and environmental compliance
through provisions which are adjusted to reflect increases or decreases in such
costs. GULF's recovery of these costs is based upon an annual projection - any
over/under recovery during such period is reflected in a subsequent annual
period with interest. With respect to MISSISSIPPI's retail rates, fuel and
purchased power costs are billed to such customers under the fuel adjustment
clause and energy costs management clause. The adjustment factors for
MISSISSIPPI's retail and wholesale rates are generally levelized based on the
estimated energy cost for the year, adjusted for any actual over/under
collection from the previous year. Revenues are adjusted for differences between
recoverable fuel costs and amounts actually recovered in current rates.
Rate Proceedings
Reference is made to MISSISSIPPI's "Management's Discussion and Analysis" in
Item 7 and to Note 3 to each registrant's financial statements in Item 8 herein
for a discussion of rate matters.
I-16
In February 2002, MISSISSIPPI reached an agreement with certain of its
wholesale customers to increase its wholesale tariff rates effective June 2002.
MISSISSIPPI filed the settlement agreement with the FERC on March 5, 2002. The
FERC has 60 days to either set the issue for hearing with the proposed rates
subject to refund or let the new rates go into effect as filed. The agreement
results in an annual increase of approximately $10.5 million and the adoption of
an Energy Cost Management Clause similar to the one approved by MISSISSIPPI's
retail jurisdiction (see Note 1 to MISSISSIPPI's financial statements in Item 8
herein). In addition, MISSISSIPPI and its customers agreed that neither party
would seek a unilateral change to the new rates prior to December 31, 2003,
except for changes due to the operation of the fuel adjustment and energy cost
management clauses. Though the FERC has accepted settlement agreements as filed
in the past, the ultimate outcome of this matter before the FERC cannot now be
determined.
On March 5, 2002, the Alabama PSC approved a revision to ALABAMA's rates
that provide for periodic adjustments based upon ALABAMA's earned return on
end-of-period retail common equity. This revision provides for an annual, rather
than quarterly, adjustment and imposes a 3 percent limit on any such annual
adjustment. A 2 percent increase in retail rates will become effective in April
2002 in accordance with the Rate Stabilization Equalization Plan. The return on
common equity range of 13.0 to 14.5 percent remains unchanged. The Alabama PSC
also accepted ALABAMA's proposal to lower the energy cost recovery factor for
the billing months April 2002 through December 2002.
Integrated Resource Planning
In July 2001, the Georgia PSC approved the GEORGIA and SAVANNAH 2001 Integrated
Resource Plan, which was filed on January 31, 2001. The plans specify how
GEORGIA and SAVANNAH each intends to meet the future electrical needs of its
customers through a combination of demand-side and supply-side resources. The
Georgia PSC must pre-certify these new resources. Once certified, all prudently
incurred construction costs and purchase power costs will be recoverable through
rates.
In July 2001, the Georgia PSC approved GEORGIA's 2003/04 certification
request, which was filed December 15, 2000, for approximately 1,800 megawatts of
purchased power and 12 megawatts of upgraded hydro generation. This
certification request included a seven-year PPA with Southern Power for two
gas-fired combined cycle units that will be constructed at Plant Goat Rock. The
first unit is designed to produce approximately 570 megawatts starting in 2003,
with approximately 370 megawatts being available by June 2002. The second unit
is designed to produce approximately 610 megawatts starting in 2004, with
approximately 400 megawatts being available by June 2003. Also, a capacity
upgrade of 12 megawatts was approved for the existing Goat Rock hydro units 1
and 2. In addition, this certification request included a seven-year PPA with
Southern Power for a gas fired combined cycle generating unit to be constructed
at Plant Autaugaville in Alabama. The unit is designed to produce approximately
610 megawatts starting in 2004. Based on an agreement with the Georgia PSC, the
seven-year term of the PPA was modified to be 15 years.
In April 2001, GEORGIA and SAVANNAH issued an RFP for their 2005/06
resource needs of approximately 2,500 megawatts. At the request of the Georgia
PSC, this RFP requested all types of generation resources including coal and
nuclear. The bids received from this RFP totaled more than 25,000 megawatts
including over 1,800 megawatts of coal offers. As required by the Georgia PSC's
2001 IRP order, GEORGIA developed a self-build coal offer to be compared to the
bid received through the RFP. In conjunction with the Georgia PSC, an economic
analysis of the coal proposals was completed and the results indicated that the
coal resources were not economical as compared to gas-fired generation at this
point in time. Therefore, the Georgia PSC relieved GEORGIA of its obligation to
continue to develop a coal self-build proposal. At the present time, the bids
from this RFP are being analyzed and the best-cost projects will be selected.
Once the PPAs have been completed for the selected projects, GEORGIA and
SAVANNAH will file for certification of these PPAs by summer of 2002.
GEORGIA and SAVANNAH expect the Georgia PSC to approve the certification request
in the fall of 2002.
I-17
Environmental Cost Recovery Plans
In 1993, the Florida Legislature adopted legislation for an Environmental Cost
Recovery Clause (ECRC), which allows a utility, including GULF, to petition the
Florida PSC for recovery of prudent environmental compliance costs that are not
being recovered through base rates or any other recovery mechanism. Such
environmental costs include operation and maintenance expense, emission
allowance expense, depreciation and a return on invested capital.
In 1992, the Mississippi PSC approved MISSISSIPPI's Environmental
Compliance Overview Plan (ECO Plan). The ECO Plan establishes procedures to
facilitate the Mississippi PSC's overview of MISSISSIPPI's environmental
strategy and provides for recovery of costs (including costs of capital
associated with environmental projects approved by the Mississippi PSC). Under
the ECO Plan, any increase in the annual revenue requirement is limited to 2
percent of retail revenues. However, the ECO Plan also provides for carryover of
any amount over the 2 percent limit into the next year's revenue requirement.
MISSISSIPPI conducts studies, when possible, to determine the extent of any
required environmental remediation. Should such remediation be determined to be
probable, reasonable estimates of costs to clean up such sites are developed and
recognized in the financial statements. MISSISSIPPI recovers such costs under
the ECO Plan as they are incurred, as provided for in MISSISSIPPI's 1995 ECO
Plan order. MISSISSIPPI filed its 2002 ECO Plan in January 2002, which, if
approved as filed, will result in a slight increase in customer prices.
Employee Relations
The SOUTHERN system had a total of 26,122 employees on its payroll at December
31, 2001.
--------------------------------------------------------------
Employees
at
December 31, 2001
-------------------------
ALABAMA 6,706
GEORGIA 9,048
GULF 1,309
MISSISSIPPI 1,316
SAVANNAH 550
SCS 3,569
Southern Nuclear 3,045
Other 579
--------------------------------------------------------------
Total 26,122
==============================================================
The operating companies have separate agreements with local unions of the
IBEW generally covering wages, working conditions and procedures for handling
grievances and arbitration. These agreements apply with certain exceptions to
operating, maintenance and construction employees.
ALABAMA has agreements with the IBEW on a three-year contract extending to
August 14, 2005. Upon notice given at least 60 days prior to that date,
negotiations may be initiated with respect to agreement terms to be effective
after such date.
GEORGIA has an agreement with the IBEW covering wages and working
conditions, which is in effect through June 30, 2002.
GULF has an agreement with the IBEW on a three-year contract extending to
August 15, 2005.
MISSISSIPPI has an agreement with the IBEW on a four-year contract extending
to August 16, 2002.
SAVANNAH has four-year labor agreements with the IBEW and the Office and
Professional Employees International Union that expire April 15, 2003 and
December 1, 2003, respectively.
Southern Nuclear has agreements with the IBEW on a five-year contract
extending to August 15, 2006 for Plant Farley and a three-year contract
extending to June 30, 2002 for Plants Hatch and Vogtle. Upon notice given at
I-18
least 60 days prior to these dates, negotiations may be initiated with respect
to agreement terms to be effective after such dates.
Southern Nuclear is currently in negotiations with the Security, Police and
Fire Professionals of America (formerly the United Plant Guard Workers of
America) at Plant Hatch. The prior contract with the United Plant Guard Workers
of America which extended to September 30, 2001 was not terminated, so the terms
of the existing agreement have continued as negotiations of the new agreement
continues. The parties will have the opportunity to terminate the agreement 60
days prior to October 1, 2002 if no agreement is reached prior to that time.
The agreements also subject the terms of the pension plans for the companies
discussed above to collective bargaining with the unions at five-year intervals.
I-19
Item 2. PROPERTIES
Electric Properties - The Electric Utilities
The operating companies, Southern Power and SEGCO, at December 31, 2001, owned
and/or operated 34 hydroelectric generating stations, 34 fossil fuel generating
stations, three nuclear generating stations and five combined cycle/cogeneration
stations. The amounts of capacity for each company are shown in the table below.
------------------------- -------------------------------------
Nameplate
Generating Station Location Capacity (1)
------------------------- ------------------- -----------------
(Kilowatts)
Fossil Steam
Gadsden Gadsden, AL 120,000
Gorgas Jasper, AL 1,221,250
Barry Mobile, AL 1,525,000
Greene County Demopolis, AL 300,000 (2)
Gaston Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (3)
---------
ALABAMA Total 6,578,538
---------
Arkwright Macon, GA 160,000
Atkinson Atlanta, GA 180,000
Bowen Cartersville, GA 3,160,000
Branch Milledgeville, GA 1,539,700
Hammond Rome, GA 800,000
McDonough Atlanta, GA 490,000
McManus Brunswick, GA 115,000
Mitchell Albany, GA 170,000
Scherer Macon, GA 750,924 (4)
Wansley Carrollton, GA 925,550 (5)
Yates Newnan, GA 1,250,000
---------
GEORGIA Total 9,541,174
---------
Crist Pensacola, FL 1,045,000
Lansing Smith Panama City, FL 305,000
Scholz Chattahoochee, FL 80,000
Daniel Pascagoula, MS 500,000 (6)
Scherer Unit 3 Macon, GA 204,500 (4)
---------
GULF Total 2,134,500
---------
Eaton Hattiesburg, MS 67,500
Sweatt Meridian, MS 80,000
Watson Gulfport, MS 1,012,000
Daniel Pascagoula, MS 500,000 (6)
Greene County Demopolis, AL 200,000 (2)
-----------
MISSISSIPPI Total 1,859,500
-----------
---------------------------------------------- ----------------
------------------------- -----------------------------------------
Nameplate
Generating Station Location Capacity
---------------------- ------------------------- ------------------
(Kilowatts)
McIntosh Effingham County, GA 163,117
Kraft Port Wentworth, GA 281,136
Riverside Savannah, GA 102,278
-----------
SAVANNAH Total 546,531
-----------
Gaston Units 1-4 Wilsonville, AL
SEGCO Total 1,000,000 (7)
-----------
Total Fossil Steam 21,660,243
-----------
Nuclear Steam
Farley Dothan, AL
ALABAMA Total 1,720,000
-----------
Hatch Baxley, GA 899,612 (8)
Vogtle Augusta, GA 1,060,240 (9)
-----------
GEORGIA Total 1,959,852
-----------
Total Nuclear Steam 3,679,852
-----------
Combustion Turbines
Greene County Demopolis, AL
ALABAMA Total 720,000
-----------
Arkwright Macon, GA 30,580
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
Intercession City Intercession City, FL 47,333 (10)
McDonough Atlanta, GA 78,800
McIntosh
Units 1,2,3,4,7,8 Effingham County, GA 480,000
McManus Brunswick, GA 481,700
Mitchell Albany, GA 118,200
Robins Warner Robins, GA 160,000
Wilson Augusta, GA 354,100
Wansley Carrollton, GA 26,322 (5)
-----------
GEORGIA Total 1,895,155
-----------
Lansing Smith
Unit A Panama City, FL 39,400
Pea Ridge
Units 1-3 Pea Ridge, FL 14,250
------
GULF Total 53,650
------
Chevron Cogenerating
Station Pascagoula, MS 147,292 (11)
Sweatt Meridian, MS 39,400
Watson Gulfport, MS 39,360
---------
MISSISSIPPI Total 226,052
---------
------------------------------------------------- -----------------
I-20
--------------------------- -------------------- -----------------
Nameplate
Generating Station Location Capacity
--------------------------- -------------------- -----------------
(Kilowatts)
Boulevard Savannah, GA 59,100
Kraft Port Wentworth,
GA 22,000
McIntosh
Units 5&6 Effingham
County, GA 160,000
-------
SAVANNAH Total 241,100
-------
Dahlberg 800,000
-------
Southern Power Total 800,000
-------
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
-----------
Total Combustion Turbines 3,955,637
-----------
Cogeneration
Washington County Washington
County, AL 123,428
GE Plastics Project Burkeville, AL 104,800
Theodore Theodore, AL 236,418
-----------
Total Cogeneration 464,646
-----------
Combined Cycle
Barry Mobile, AL
ALABAMA Total 1,070,424
---------
Daniel
(Leased) Pascagoula, MS
Mississippi Total 1,070,424
---------
Total Combined Cycle 2,140,848
---------
Hydroelectric Facilities
Weiss Leesburg, AL 87,750
Henry Ohatchee, AL 72,900
Logan Martin Vincent, AL 128,250
Lay Clanton, AL 177,000
Mitchell Verbena, AL 170,000
Jordan Wetumpka, AL 100,000
Bouldin Wetumpka, AL 225,000
Harris Wedowee, AL 135,000
Martin Dadeville, AL 154,200
Yates Tallassee, AL 32,000
Thurlow Tallassee, AL 60,000
Lewis Smith Jasper, AL 157,500
Bankhead Holt, AL 54,000
Holt Holt, AL 46,000
----------
ALABAMA Total 1,599,600
----------
--------------------------- -------------------- -----------------
--------------------------- -------------------- -----------------
Nameplate
Generating Station Location Capacity
--------------------------- -------------------- -----------------
Barnett Shoals
(Leased) Athens, GA 2,800
Bartletts Ferry Columbus, GA 173,000
Goat Rock Columbus, GA 26,000
Lloyd Shoals Jackson, GA 14,400
Morgan Falls Atlanta, GA 16,800
North Highlands Columbus, GA 29,600
Oliver Dam Columbus, GA 60,000
Rocky Mountain Rome, GA 215,256 (12)
Sinclair Dam Milledgeville, GA 45,000
Tallulah Falls Clayton, GA 72,000
Terrora Clayton, GA 16,000
Tugalo Clayton, GA 45,000
Wallace Dam Eatonton, GA 321,300
Yonah Toccoa, GA 22,500
6 Other Plants 18,080
-----------
GEORGIA Total 1,077,736
-----------
Total Hydroelectric Facilities 2,677,336
-----------
Total Generating Capacity 34,578,562
===========
------------------------------------------------ -----------------
Notes:
(1) For additional information regarding facilities jointly-owned with
non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein.
(2) Owned by ALABAMA and MISSISSIPPI as
tenants in common in the proportions of 60% and 40%, respectively.
(3) Excludes the capacity owned by AEC.
(4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3.
Capacity shown for GULF is 25% of Unit 3.
(5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
(6) Represents 50% of the plant which is owned as tenants in common by
GULF and MISSISSIPPI.
(7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS
herein.)
(8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
(9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
(10) Capacity shown represents 33-1/3% of total plant capacity. GEORGIA owns
a 1/3 interest in the unit with 100% use of the unit from June through
September. FPC operates the unit.
(11) Generation is dedicated to a single industrial customer.
(12) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity.
OPC operates the plant.
I-21
Except as discussed below under "Titles to Property," the principal plants
and other important units of the operating companies, Southern Power and SEGCO
are owned in fee by the respective companies. It is the opinion of management of
each such company that its operating properties are adequately maintained and
are substantially in good operating condition.
MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which
is leased to Entergy Gulf States. The line, completed in 1984, extends from
Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use
fee over a forty-year period covering all expenses and the amortization of the
original $57 million cost of the line. At December 31, 2001, the unamortized
portion of this cost was approximately $33.3 million.
The all-time maximum demand on the operating companies and SEGCO was
31,359,000 kilowatts and occurred in August 2000. This amount excludes demand
served by capacity retained by MEAG and Dalton and excludes demand associated
with power purchased from OPC and SEPA by its preference customers. The reserve
margin for the operating companies and SEGCO at that time was 8.1%. For
additional information on peak demands, reference is made to Item 6 - SELECTED
FINANCIAL DATA herein.
ALABAMA and GEORGIA will incur significant costs in decommissioning their
nuclear units at the end of their useful lives. (See Item 1 - BUSINESS -
"Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.)
Jointly-Owned Facilities
ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in
certain generating plants and other related facilities to or from non-affiliated
parties. The percentages of ownership resulting from these transactions are as
follows:
Total Percentage Ownership
---------------- -------- ------------ -------- --------- ------------ --------
Capacity ALABAMA AEC GEORGIA OPC MEAG DALTON FPC
-------------- ---------------- -------- ------------ -------- --------- ------------ --------
(Megawatts)
Units 1 and 2 1,320 91.8% 8.2% -% -% -% -% -%
Plant Hatch 1,796 - - 50.1 30.0 17.7 2.2 -
Plant Vogtle 2,320 - - 45.7 30.0 22.7 1.6 -
Plant Scherer
Units 1 and 2 1,636 - - 8.4 60.0 30.2 1.4 -
Plant Wansley 1,779 - - 53.5 30.0 15.1 1.4 -
Rocky Mountain 848 - - 25.4 74.6 - - -
Intercession City, FL 142 - - 33.3 - - - 66.7
----------------------------- -------------- -- ---------------- -------- ------------ -------- --------- ------------ --------
ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain and Intercession
City, as described below) as agent for the joint owners.
In addition, GEORGIA has commitments regarding a portion of a 5 percent
interest in Plant Vogtle owned by MEAG that are in effect until the later of
retirement of the plant or the latest stated maturity date of MEAG's bonds
issued to finance such ownership interest. The payments for capacity are
required whether any capacity is available. The energy cost is a function of
each unit's variable operating costs. Except for the portion of the capacity
payments related to the 1987 and 1990 write-offs of Plant Vogtle costs, the
cost of such capacity and energy is included in purchased power from
non-affiliates in GEORGIA's Statements of Income in Item 8 herein.
I-22
Additional jointly-owned facilities also include Southern Power's 65%
undivided interest in Stanton Unit A and related facilities jointly owned with
the Orlando Utilities Commission, the Kissimmee Utility Authority and the
Florida Municipal Power Agency. Currently under construction near Orlando,
Florida, this project will be a 610 megawatt combined cycle unit and is
scheduled for commerical operation in October 2003.
Titles to Property
The operating companies', Southern Power's and SEGCO's interests in the
principal plants (other than certain pollution control facilities, one small
hydroelectric generating station leased by GEORGIA, MISSISSIPPI's combined cycle
units at Plant Daniel and the land on which five combustion turbine generators
of MISSISSIPPI are located, which is held by easement) and other important units
of the respective companies are owned in fee by such companies, subject only to
the liens of applicable mortgage indentures of ALABAMA, GULF, MISSISSIPPI and
SAVANNAH and to excepted encumbrances as defined therein. The operating
companies own the fee interests in certain of their principal plants as tenants
in common. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.)
Properties such as electric transmission and distribution lines and steam
heating mains are constructed principally on rights-of-way which are maintained
under franchise or are held by easement only. A substantial portion of lands
submerged by reservoirs is held under flood right easements. In substantially
all of its coal reserve lands, SEGCO owns or will own the coal only, with
adequate rights for the mining and removal thereof.
I-23
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. ALABAMA
(United States District Court for the Northern District of Alabama)
On November 3, 1999, the EPA brought a civil action in the U.S. District
Court in Georgia against ALABAMA. The complaint alleges violations of the
New Source Review provisions of the Clean Air Act with respect to
coal-fired generating facilities at ALABAMA's Plants Miller, Barry and
Gorgas. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available
control technology at the affected units. The Clean Air Act authorizes
civil penalties of up to $27,500 per day, per violation at each
generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day. The EPA concurrently issued a notice of violation relating to these
specific facilities, as well as Plants Greene County and Gaston. On
August 1, 2000, the U.S. District Court granted ALABAMA's motion to
dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA
re-filed its claims against ALABAMA in federal district court in
Birmingham, Alabama. ALABAMA's case has been stayed since the spring of
2001, pending a ruling by the U.S. Court of Appeals for the Eleventh
Circuit in the appeal of a very similar New Source Review enforcement
action against the TVA. The TVA case involves many of the same legal
issues raised by the actions against ALABAMA. Because the outcome of the
TVA case could have a significant adverse impact on ALABAMA, ALABAMA is
party to that case as well.
ALABAMA believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in
question took place. An adverse outcome of this matter could require
substantial capital expenditures that cannot be determined at this time
and possibly require payment of substantial penalties.
(2) United States of America v. GEORGIA and SAVANNAH
(United States District Court for the Northern District of Georgia)
On November 3, 1999, the EPA brought a civil action in the U.S. District
Court in Georgia against GEORGIA. The complaint alleges violation of the
New Source Review provisions of the Clean Air Act with respect to
coal-fired generating facilities at GEORGIA's Plants Bowen and Scherer.
The civil action requests penalties and injunctive relief, including an
order requiring the installation of the best available control technology
at the affected units. The Clean Air Act authorizes civil penalties of up
to $27,500 per day, per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day. On March 27, 2001, the
U.S. District Court granted the EPA's motion to amend its complaint to
add the alleged violations at SAVANNAH's Plant Kraft and to add SAVANNAH
as a defendant. The EPA concurrently issued a notice of violation
relating to these two GEORGIA plants and SAVANNAH's Plant Kraft.
The case has been stayed since the spring of 2001, pending a ruling by
the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a
very similar New Source Review enforcement action against the TVA. The
TVA case involves many of the same legal issues raised by the actions
against GEORGIA and SAVANNAH. Because the outcome of the TVA case could
have a significant adverse impact on GEORGIA and SAVANNAH, both GEORGIA
and SAVANNAH are party to that case as well.
GEORGIA and SAVANNAH believe that they complied with applicable laws and
the EPA's regulations and interpretations in effect at the time the work
in question took place. An adverse outcome of this matter could require
substantial capital expenditures that cannot be determined at this time
and possibly require payment of substantial penalties.
I-24
Item 3. LEGAL PROCEEDINGS (continued)
(3) Cooper et al. v. GEORGIA, SOUTHERN, SCS and Energy Solutions
(Superior Court of Fulton County, Georgia)
On July 28, 2000, a lawsuit alleging race discrimination was filed by
three GEORGIA employees against GEORGIA, SOUTHERN, and SCS in the
Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit
was removed to the United States District Court for the Northern District
of Georgia. The lawsuit also raised claims on behalf of a purported
class. The plaintiffs seek compensatory and punitive damages in an
unspecified amount, as well as injunctive relief. On August 14, 2000, the
lawsuit was amended to add four more plaintiffs. Also, an additional
subsidiary of SOUTHERN, Energy Solutions (now Southern Management
Development), was named a defendant.
On October 11, 2001, the district court denied the plaintiffs' motion for
class certification. The plaintiffs filed a motion to reconsider the
order denying class certification, and the court denied the plaintiffs'
motion to reconsider. On December 28, 2001, the plaintiffs filed a
petition in the United States Court of Appeals for the Eleventh Circuit
seeking permission to file an appeal of the October 11 decision. On March
15, 2002, the Eleventh Circuit denied the plaintiffs' petition; thus, the
plaintiffs may not appeal the October 11 decision until the seven
individual cases are resolved in the district court. Discovery on the
seven named plaintiffs' individual claims that remain in the case is
ongoing. The final outcome of the case cannot now be determined.
(4) GEORGIA has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act.
In addition, in 1995 the EPA designated GEORGIA and four other unrelated
entities as potentially responsible parties at a site in Brunswick,
Georgia that is listed on the federal National Priorities List. GEORGIA
has contributed to the removal and remedial investigation and feasibility
study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated.
The final outcome of these matters cannot now be determined.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein under the captions "Georgia Power Potentially
Responsible Party Status" and "Other Environmental Contingencies,"
respectively.
(5) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy
Services Holdings, Inc.
(U.S. Bankruptcy Court for the Southern District of Alabama).
On August 4, 2000, MESH filed a proposed plan of reorganization with the
U.S. Bankruptcy Court. The proposed plan of reorganization was most
recently amended on October 15, 2001. SOUTHERN expects that approval of a
plan of reorganization would result in either a termination of SOUTHERN's
ownership interest in MESH or the exchange of all assets of MESH for the
cancellation of securities held by the bondholders, but would not affect
SOUTHERN's continuing guarantee obligations. The final outcome of this
matter cannot now be determined.
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
herein under the caption "Mobile Energy Services' Petition for
Bankruptcy."
I-25
Item 3. LEGAL PROCEEDINGS (continued)
(6) Gordon v. SOUTHERN et al.
(United States District Court for the Southern District of California)
and
(7) Pier 23 Restaurant v. SOUTHERN et al.
(United States District Court for the Northern District of California)
Prior to the spin off of Mirant, SOUTHERN was named as a defendant in two
lawsuits filed in the superior courts of California alleging that certain
owners of electric generation facilities in California, including
SOUTHERN, engaged in various unlawful and anticompetitive acts that
served to manipulate wholesale power markets and inflate wholesale
electricity prices in California. One lawsuit naming SOUTHERN, Mirant and
other generators as defendants alleged that, as a result of the
defendants' conduct, customers paid approximately $4 billion more for
electricity that they otherwise would have and sought an award of treble
damages, as well as other injunctive and equitable relief. The other suit
likewise sought treble damages and equitable relief. The allegations in
the two lawsuits in which SOUTHERN was named seemed to be directed to
activities of subsidiaries of Mirant. On September 28 and November 6,
2001, the plaintiffs voluntarily dismissed SOUTHERN without prejudice
from the two lawsuits in which it had been named as a defendant. Prior to
being dismissed, SOUTHERN had notified Mirant of its claim for
indemnification for costs associated with the lawsuits under the terms of
the master separation agreement that governs the spin off of Mirant.
Mirant had undertaken the defense of the lawsuits. Plaintiffs would not
be barred by their own dismissal from naming SOUTHERN in some future
lawsuit, but management believes that the likelihood of SOUTHERN having
to pay damages in any such lawsuit is remote.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- - Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's
financial statements in Item 8 herein for a description of certain other
administrative and legal proceedings discussed therein.
Additionally, each of the operating companies, SCS, Southern Nuclear,
Southern Power, Energy Solutions and Southern LINC are, in the normal course of
business, engaged in litigation or administrative proceedings that include, but
are not limited to, acquisition of property, injuries and damages claims, and
complaints by present and former employees.
I-26
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
ALABAMA
ALABAMA held a special meeting of shareholders on November 21, 2001
for the purpose of amending its charter to effect certain changes in
the Auction Procedures for ALABAMA's 1988 Auction Series Class A
Preferred Stock and 1993 Auction Series Class A Preferred Stock. The
amendment was passed and the vote tabulation was as follows:
Votes
------------------------------------------------
For Against Abstain
--- ------- -------
Common Stock 6,000,000 0 0
Preferred Stock 377,000 0 0
---------- - -
Total 6,377,000 0 0
========= = =
I-27
EXECUTIVE OFFICERS OF SOUTHERN
(Identification of executive officers of SOUTHERN is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.
H. Allen Franklin
Chairman, President, Chief Executive Officer and Director
Age 57
Elected Director in 1988 and Chief Executive Officer effective March 1, 2001.
Previously served as President and Chief Operating Officer of SOUTHERN from June
1999 to March 2001; and as President and Chief Executive Officer of GEORGIA from
January 1994 to June 1999.
Dwight H. Evans
Executive Vice President
Age 53
Elected in 2001. Previously served as President and Chief Executive Officer of
MISSISSIPPI from March 1995 to May 2001.
David M. Ratcliffe
Executive Vice President
Age 53
Elected in 1999. He also has served as President and Chief Executive Officer of
GEORGIA since June 1999. Previously served as Executive Vice President,
Treasurer and Chief Financial Officer of GEORGIA from March 1998 to June 1999;
and as Senior Vice President of SOUTHERN from March 1995 to March 1998.
Leonard J. Haynes
Executive Vice President and Chief Marketing Officer
Age 51
Elected in 2001. Previously served as Senior Vice President of GEORGIA from
October 1998 to May 2001; and Vice President of GEORGIA from October 1992 to
October 1998.
G. Edison Holland, Jr.
Executive Vice President
Age 49
Elected in 2001. Previously served as President and Chief Executive Officer of
SAVANNAH from 1997 until 2001.
Gale E. Klappa
Executive Vice President, Chief Financial Officer and Treasurer
Age 51
Elected in 2001. Previously served as Financial Vice President, Chief Financial
Officer and Treasurer form March 2001 to May 2001; Senior Vice President and
Chief Strategic Officer of SOUTHERN from October 1999 to March 2001; President
of Mirant's North America Group and Senior Vice President of Mirant from
December 1998 to October 1999; and as President and Chief Executive Officer of
Western Power Distribution, a subsidiary of Mirant located in Bristol, England,
from September 1995 to December 1998.
Charles D. McCrary
Executive Vice President
Age 50
Elected in 1998; serves as President and Chief Executive Officer of ALABAMA.
Previously served as President and Chief Operating Officer of ALABAMA from May
2001 to October 2001; Vice President of SOUTHERN from February 1998 to April
2001; and as Executive Vice President of ALABAMA from 1994 through February
1998.
W. Paul Bowers
Age 44
Executive Vice President of SCS and President and Chief Executive Officer of
Southern Power since May 2001. Previously served as Senior Vice President of SCS
and Chief Marketing Officer of SOUTHERN from March 2000 to May 2001; President
and Chief Executive Officer of Western Power Distribution, a subsidiary of
Mirant located in Bristol, England, from December 1998 to 2000; and Senior Vice
President of Retail Marketing for GEORGIA from 1995 to 1998.
W. G. Hairston, III
Age 57
President and Chief Executive Officer of Southern Nuclear since 1993.
The officers of SOUTHERN were elected for a term running from the first
meeting of the directors following the last annual meeting (May 23, 2001) for
one year until the first board meeting after the next annual meeting or until
their successors are elected and have qualified.
I-28
EXECUTIVE OFFICERS OF ALABAMA
(Identification of executive officers of ALABAMA is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.
Elmer B. Harris
Chairman and Director*
Age 62
Elected in 1989. Served as President and Chief Executive Officer from 1989 to
2001. Elected Executive Vice President of SOUTHERN in 1991. Served as a Director
of SOUTHERN since 1989.
Charles D. McCrary
President, Chief Executive Officer and Director
Age 50
Elected in 2001. Served as President and Chief Operating Officer of ALABAMA from
April 2001 to October 2001 and Vice President of SOUTHERN from February 1998 to
April 2001. Previously served as Executive Vice President of External Affairs at
ALABAMA from April 1994 through February 1998.
William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 58
Elected in 1991. Served as Treasurer since 1998 in addition to Executive Vice
President and Chief Financial Officer since 1991.
C. Alan Martin
Executive Vice President
Age 53
Elected in 1999. Served as Executive Vice President of External Affairs since
January 2000. Previously served as Executive Vice President and Chief Marketing
Officer for SOUTHERN from 1998 to 1999; and Vice President of Human Resources
for SOUTHERN from May 1995 to March 1998.
Steve R. Spencer
Executive Vice President
Age 46
Elected in 2001. Served as Senior Vice President of External Affairs from July
2000 to April 2001. Previously served as Vice President of SOUTHERN's external
affairs organization from 1998 to 2001.
Jerry L. Stewart
Senior Vice President
Age 52
Elected in 1999. Served as Senior Vice President of Fossil and Hydro Generation
since 1999. Previously served as Vice President of SCS from 1992 to 1999.
The officers of ALABAMA were elected for a term running from the last
annual meeting of the directors (April 27, 2001) for one year until the next
annual meeting or until their successors are elected and have qualified, except
for Mr. McCrary who was elected Chief Executive Officer on October 25, 2001.
*Retired effective January 11, 2002.
I-29
EXECUTIVE OFFICERS OF GEORGIA
(Identification of executive officers of GEORGIA is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.
David M. Ratcliffe
President, Chief Executive Officer and Director
Age 53
Elected as an Executive Officer in 1998 and as Director in 1999. Served as
President and Chief Executive Officer since June 1999. Previously served as
Executive Vice President, Treasurer and Chief Financial Officer of GEORGIA from
1998 to 1999; and as Senior Vice President of SOUTHERN from March 1995 to March
1998.
William C. Archer, III
Executive Vice President
Age 53
Elected in 1995. Served as Executive Vice President of External Affairs since
1995.
Thomas A. Fanning
Executive Vice President, Treasurer and
Chief Financial Officer
Age 44
Elected in 1999. Previously served as Senior Vice President of SCS and Chief
Information Officer for SOUTHERN from March 1995 to June 1999.
Judy M. Anderson
Senior Vice President
Age 53
Elected in 2001. Served as Senior Vice President of Charitable Giving since
2001. Previously served as Vice President and Corporate Secretary of GEORGIA
from 1989 to 2001.
Ronnie L. Bates
Senior Vice President
Age 47
Elected in 2001. Served as Senior Vice President, Marketing since 2001.
Previously served as Vice President, Transmission from 2000 to 2001; and as
General Manager, Transmission and Construction from 1995 to 2000.
Mickey A. Brown
Senior Vice President
Age 54
Elected in 2001. Served as Senior Vice President of Distribution since 2001.
Previously served as Vice President, Distribution from 2000 to 2001; and as Vice
President, Northern Region from 1993 to 2000.
James K. Davis
Senior Vice President
Age 61
Elected in 1993. Served as Senior Vice President of Corporate Relations since
1993, with Employee Relations being added to his responsibilities in 2000.
Fred D. Williams
Senior Vice President
Age 57
Elected in 1992. Served as Senior Vice President of Resource Policy and Planning
since 1997. Previously served as Senior Vice President of Wholesale Energy from
1995 to 1997.
Leslie R. Sibert
Vice President
Age 39
Elected in 2001. Served as Vice President, Transmission since 2001. Previously
served as Decatur Region Manager from 1999 to 2001; and as Assistant to Senior
Vice President, Southern Wholesale Energy from 1996 to 1999.
Christopher C. Womack
Senior Vice President
Age 43
Elected in 2001. Served as Senior Vice President of Fossil and Hydro since 2001.
Previously served as Vice President and Chief People Officer of SOUTHERN from
1998 to 2001; and as Senior Vice President of Public Relations and Corporate
Services at ALABAMA from 1995 to 1998.
The officers of GEORGIA were elected for a term running from the last annual
meeting of the directors (May 16, 2001) for one year until the next annual
meeting or until their successors are elected and have qualified, except for Ms.
Anderson, whose election was effective June 1, 2001; Mr. Bates, whose election
was effective October 8, 2001; Ms. Sibert, whose election was effective November
14, 2001; and Mr. Womack, whose election was effective December 17, 2001.
I-30
EXECUTIVE OFFICERS OF GULF
(Identification of executive officers of GULF is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.
Travis J. Bowden
President, Chief Executive Officer and Director
Age 63
Elected in 1994. Served as President and Chief Executive Officer since 1994.
Francis M. Fisher, Jr.
Vice President
Age 53
Elected in 1989. Served as Vice President of Power Delivery and Customer
Operations since 1996.
John E. Hodges, Jr.
Vice President
Age 58
Elected in 1989. Served as Vice President of Marketing and Employee/External
Affairs since 1996.
Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
Age 48
Elected in 2000. Served as Vice President, Chief Financial Officer and
Comptroller since 2001. Previously served as Comptroller and Chief Financial
Officer from 2000 to 2001 and Controller from 1992 to 2000.
Robert G. Moore
Vice President
Age 52
Elected in 1997. Served as Vice President of Power Generation and Transmission
of GULF and Vice President of Fossil Generation of SCS since 1997. Previously
served as Plant Manager of Plant Bowen at GEORGIA from March 1993 to August
1997.
Warren E. Tate
Vice President, Secretary/Treasurer and
Regional Chief Information Officer
Age 59
Elected in 2000. Served as Vice President since 2001, also serves as
Secretary/Treasurer and Regional Chief Information Officer since 1996.
The officers of GULF were elected for a term running from the last annual
meeting of the directors (July 27, 2001) for one year until the next annual
meeting or until their successors are elected and have qualified.
I-31
EXECUTIVE OFFICERS OF MISSISSIPPI
(Identification of executive officers of MISSISSIPPI is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.
Michael D. Garrett
President, Chief Executive Officer and Director
Age 52
Elected in 2001. Previously served as Executive Vice President - Customer
Service of ALABAMA from January 2000 to May 2001; Executive Vice President of
External Affairs of ALABAMA from March 1998 to January 2000; and Senior Vice
President of External Affairs of ALABAMA from February 1994 to March 1998.
H. E. Blakeslee
Vice President
Age 61
Elected in 1984. Served as Vice President of Customer Services and Retail
Marketing since 1984.
Don E. Mason
Vice President
Age 60
Elected in 1983. Served as Vice President of External Affairs and Corporate
Services since 1983.
Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer
Age 49
Elected in 1995. Served as Vice President, Treasurer and Chief Financial
Officer since 2001. Previously served as Vice President,
Secretary, Treasurer and Chief Financial Officer from 1995 to 2001.
Gene L. Ussery, Jr.
Vice President
Age 52
Elected in 2000. Served as Vice President of Power Generation and Delivery since
September 2000. Previously served as Northern Cluster Manager at GEORGIA for
Plants Hammond, Bowen and McDonough-Atkinson from July 2000 to September 2000.
He served as Manager of Plant Bowen at GEORGIA from 1997 to 2000; and Manager of
Plant McDonough at GEORGIA from 1996 to 1997.
The officers of MISSISSIPPI were elected for a term running from the last
annual meeting of the directors (April 25, 2001) for one year until the next
annual meeting or until their successors are elected and have qualified.
I-32
PART II
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) The common stock of SOUTHERN is listed and traded on the New York
Stock Exchange. The stock is also traded on regional exchanges across
the United States. High and low stock prices, per the New York Stock
Exchange Composite Tape during each quarter for the past two years
were as follows:
------------------------ ------------ -- --------------
High Low
------------ --------------
2001
First Quarter (Note) $21.650 $16.152
Second Quarter 23.880 20.890
Third Quarter 26.000 22.050
Fourth Quarter 25.980 22.300
2000
First Quarter $25.875 $20.375
Second Quarter 27.875 21.688
Third Quarter 35.000 23.406
Fourth Quarter 33.880 27.500
---------------------- -------------- -- --------------
Note: The common stock high and low prices have been adjusted to
give effect to the Mirant spin off. Reference is made to Note
11 to the financial statements for SOUTHERN in Item 8 herein
for additional information.
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 28, 2002, the closing price
of SOUTHERN's common stock was $25.40.
(b) Number of SOUTHERN's common stockholders of record at December 31,
2001:
150,242
Each of the other registrants have one common stockholder, SOUTHERN.
(c) Dividends on each registrant's common stock are payable at the
discretion of their respective board of directors. The dividends on
common stock declared by SOUTHERN and the operating companies to
their stockholder(s) for the past two years were as follows: (in
thousands)
------------------- --------- ------------- ----------
Registrant Quarter 2001 2000
------------------- --------- ------------- ----------
SOUTHERN First $228,320 $220,557
Second 229,611 217,289
Third 231,192 217,289
Fourth 232,935 218,098
ALABAMA First 101,200 103,600
Second 97,600 105,200
Third 97,600 104,400
Fourth 97,500 103,900
GEORGIA First 134,500 136,500
Second 130,900 138,600
Third 130,900 137,600
Fourth 131,000 136,900
GULF First 13,500 14,600
Second 13,300 14,900
Third 13,300 14,800
Fourth 13,175 14,700
MISSISSIPPI First 12,800 13,600
Second 12,500 13,800
Third 12,500 13,700
Fourth 12,400 13,600
SAVANNAH First 5,500 6,100
Second 5,400 6,200
Third 5,400 6,000
Fourth 5,400 6,000
------------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of
2000 and 2001. The dividend paid on SOUTHERN's common stock for the first
quarter of 2002 was 33.5(cent) per share.
The amount of dividends on their common stock that may be paid by the
subsidiary registrants (except GEORGIA effective February 27, 2002) is
restricted in accordance with their respective first mortgage bond indenture.
The amounts of earnings retained in the
II-1
business and the amounts restricted against the payment of cash dividends on
common stock at December 31, 2001 were as follows:
-------------------- ------------------ --- --------------
Retained Restricted
Earnings Amount
------------------ --------------
(in millions)
ALABAMA $1,220 $ 796
GEORGIA 1,871 1,037
GULF 161 127
MISSISSIPPI 186 118
SAVANNAH 110 68
Consolidated 4,517 2,145
-------------------- ------------------ --- --------------
Item 6. SELECTED FINANCIAL DATA
SOUTHERN. Reference is made to information under the heading "Selected
Consolidated Financial and Operating Data," contained herein at pages II-43 and
II-44.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-78 and II-79.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-114 and II-115.
GULF. Reference is made to information under the heading "Selected Financial
and Operating Data," contained herein at pages II-145 and II-146.
MISSISSIPPI. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-178 and II-179.
SAVANNAH. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-207 and II-208.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
SOUTHERN. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-8 through II-18.
ALABAMA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-48 through II-57.
GEORGIA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-83 through II-92.
GULF. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-119 through II-128.
MISSISSIPPI. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-150 through II-159.
SAVANNAH. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-183 through II-191.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in SOUTHERN's "Management's Discussion and
Analysis - Market Price Risk" and to Note 1 to SOUTHERN's financial statements
under the heading "Financial Instruments" contained herein on pages II-14 and
II-29 through II-30, respectively.
Reference is also made to "Management's Discussion and Analysis - Exposure to
Market Risks" in Item 7 of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
contained herein at pages II-53, II-87 through II-88, II-124, II-155 and II-187,
respectively.
II-2
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2001 FINANCIAL STATEMENTS
Page
The Southern Company and Subsidiary Companies:
Report of Independent Public Accountants................................................................................ II-7
Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999.................................. II-19
Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999.............................. II-20
Consolidated Balance Sheets at December 31, 2001 and 2000............................................................... II-21
Consolidated Statements of Capitalization at December 31, 2001 and 2000................................................. II-23
Consolidated Statements of Common Stockholders' Equity for the Years Ended
December 31, 2001, 2000 and 1999..................................................................................... II-25
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2001, 2000 and 1999..................................................................................... II-25
Notes to Financial Statements........................................................................................... II-26
ALABAMA:
Report of Independent Public Accountants .............................................................................. II-47
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-58
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-59
Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-60
Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-62
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2001, 2000 and 1999.................................................................................... II-64
Notes to Financial Statements........................................................................................... II-65
GEORGIA:
Report of Independent Public Accountants................................................................................ II-82
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-93
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-94
Balance Sheets at December 31, 2001 and 2000............................................................................ II-95
Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-97
Statements of Comprehensive Income for the Years Ended
December 31, 2001, 2000 and 1999.................................................................................... II-99
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2001, 2000 and 1999.................................................................................... II-99
Notes to Financial Statements........................................................................................... II-100
GULF:
Report of Independent Public Accountants................................................................................ II-118
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-129
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-130
Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-131
Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-133
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2001, 2000 and 1999.................................................................................... II-134
Notes to Financial Statements........................................................................................... II-135
II-3
Page
MISSISSIPPI:
Report of Independent Public Accountants................................................................................ II-149
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-160
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-161
Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-162
Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-164
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2001, 2000 and 1999.................................................................................... II-166
Notes to Financial Statements........................................................................................... II-167
SAVANNAH:
Report of Independent Public Accountants................................................................................ II-182
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999............................................... II-192
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999........................................... II-193
Balance Sheets at December 31, 2001 and 2000 ........................................................................... II-194
Statements of Capitalization at December 31, 2001 and 2000 ............................................................. II-196
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2001, 2000 and 1999.................................................................................... II-197
Notes to Financial Statements........................................................................................... II-198
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
II-4
SOUTHERN COMPANY
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 2001 Annual Report
The management of Southern Company has prepared -- and is responsible for -- the
consolidated financial statements and related information included in this
report. These statements were prepared in accordance with accounting principles
generally accepted in the United States and necessarily include amounts that are
based on the best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
The company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The company's system of internal accounting controls is evaluated on an
ongoing basis by the company's internal audit staff. The company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of four independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the consolidated financial statements present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Southern Company and its subsidiary companies in conformity
with accounting principles generally accepted in the United States.
/s/H. Allen Franklin
H. Allen Franklin
Chairman, President, and Chief Executive Officer
/s/Gale E. Klappa
Gale E. Klappa
Executive Vice President, Chief Financial Officer,
and Treasurer
February 13, 2002
II-6
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Southern Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southern Company (a Delaware corporation) and
subsidiary companies as of December 31, 2001 and 2000, and the related
consolidated statements of income, comprehensive income, common stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements (pages II-19 through
II-42) referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 2001
and 2000, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Southern Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 2001 Annual Report
RESULTS OF OPERATIONS
- ---------------------
OVERVIEW OF CONSOLIDATED EARNINGS AND DIVIDENDS
Earnings
Southern Company's basic earnings per share from continuing operations increased
6.6 percent in 2001. This increase was achieved by cost containment and lower
interest rates despite the mild temperatures and the economic downturn. Basic
earnings per share from continuing operations were $1.62 in 2001 compared with
$1.52 in 2000. Dilution -- which factors in additional shares related to stock
options -- decreased earnings per share by 1 cent in 2001 and had no impact in
2000.
In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant Corporation -- formerly Southern Energy, Inc. -- and
intentions to spin off its remaining ownership of 272 million Mirant shares. On
April 2, 2001, the tax-free distribution of Mirant shares was completed at a
ratio of approximately 0.4 for every share of Southern Company common stock.
As a result of the spin off, Southern Company's financial statements and
related information reflect Mirant as discontinued operations. Therefore, the
focus of Management's Discussion and Analysis is on Southern Company's
continuing operations. The following chart shows earnings from continuing and
discontinued operations:
Consolidated Basic Earnings
Net Income Per Share
-------------- -----------------
2001 2000 2001 2000
-------------- -----------------
(in millions)
Earnings from --
Continuing
operations $1,120 $ 994 $1.62 $1.52
Discontinued
operations 142 319 0.21 0.49
- ----------------------------------------------------------------
Total earnings $1,262 $1,313 $1.83 $2.01
================================================================
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends
paid on common stock in 2001 and 2000 were $1.34 per share or 331/2 cents per
quarter. In January 2002, Southern Company declared a quarterly dividend of
331/2 cents per share. This is the 217th consecutive quarter that Southern
Company has paid a dividend equal to or higher than the previous quarter. Our
dividend payout ratio goal is 75 percent.
SOUTHERN COMPANY BUSINESS ACTIVITIES
Discussion of the results of continuing operations is focused on Southern
Company's primary business of electricity sales by the operating companies --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- and Southern Power. Southern Power is a new electric wholesale
generation subsidiary with market-based rates. The remaining portion of Southern
Company's other business activities include telecommunications, energy products
and services, leveraged leasing activities, and as the parent holding
company. The net impact of these other business activities on the consolidated
results of operations is not significant. See Note 12 to the financial
statements for additional information.
Electricity Business
Southern Company's electric utilities generate and sell electricity to retail
and wholesale customers in the Southeast. A condensed income statement for these
six companies is as follows:
Increase (Decrease)
Amount From Prior Year
------- ----------------------
2001 2001 2000
- -----------------------------------------------------------------
(in millions)
Operating revenues $9,906 $ 46 $735
- -----------------------------------------------------------------
Fuel 2,577 13 236
Purchased power 718 41 268
Other operation
and maintenance 2,489 19 40
Depreciation
and amortization 1,144 9 89
Taxes other than
income taxes 533 1 11
- -----------------------------------------------------------------
Total operating expenses 7,461 83 644
- -----------------------------------------------------------------
Operating income 2,445 (37) 91
Other income, net 15 51 2
- -----------------------------------------------------------------
Earnings before
interest and taxes 2,460 14 93
Interest expenses
and other, net 609 (25) 29
Income taxes 702 (1) 28
- -----------------------------------------------------------------
Net income $1,149 $ 40 $ 36
=================================================================
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Revenues
Operating revenues for the core business of selling electricity in 2001 and the
amount of change from the prior year are as follows:
Increase (Decrease)
Amount From Prior Year
------ ----------------------
2001 2001 2000
- ----------------------------------------------------------------
(in millions)
Retail --
Base revenues $5,921 $ (93) $174
Fuel cost recovery
and other 2,519 (67) 336
- ----------------------------------------------------------------
Total retail 8,440 (160) 510
- ----------------------------------------------------------------
Sales for resale --
Within service area 338 (39) 27
Outside service area 836 236 127
- ----------------------------------------------------------------
Total sales for resale 1,174 197 154
Other operating
revenues 292 9 71
- ----------------------------------------------------------------
Operating revenues $9,906 $ 46 $735
================================================================
Percent change 0.5% 8.1%
- ----------------------------------------------------------------
Base revenues declined by $93 million in 2001 because of mild temperatures
and the economic downturn. Total base revenues of $6.0 billion in 2000 increased
as a result of continued customer growth in the service area and the positive
impact of weather on energy sales.
Electric rates -- for the operating companies -- include provisions to adjust
billings for fluctuations in fuel costs, the energy component of purchased power
costs, and certain other costs. Under these fuel cost recovery provisions, fuel
revenues generally equal fuel expenses -- including the fuel component of
purchased energy -- and do not affect net income. However, cash flow is affected
by the economic loss from untimely recovery of these receivables.
Sales for resale revenues within the service area were $338 million in 2001,
down 10.2 percent from the prior year. This sharp decline resulted primarily
from the mild weather experienced in the Southeast during 2001, which
significantly reduced energy requirements from these customers. Sales for resale
within the service area for 2000 were up from the prior year as a result of
additional demand for electricity during the hot summer.
Revenues from energy sales for resale outside the service area have increased
sharply the past two years with a 39 percent and 27 percent increase in 2001 and
2000, respectively. This growth was primarily driven by new contracts. As
Southern Company increases its competitive wholesale generation business, sales
for resale outside the service area should reflect steady increases over the
near term. Recent wholesale contracts have shorter contract periods, and many
are market priced compared with the traditional cost-based contracts entered
into in the 1980s. Those long-term cost-based contracts are principally unit
power sales to Florida utilities. Revenues from long-term unit power contracts
have both capacity and energy components. Capacity revenues reflect the
recovery of fixed costs and a return on investment under the contracts. Energy
is generally sold at variable cost. The capacity and energy components of the
unit power contracts were as follows:
2001 2000 1999
- --------------------------------------------------------------
(in millions)
Capacity $170 $177 $174
Energy 201 178 157
- --------------------------------------------------------------
Total $371 $355 $331
==============================================================
Capacity revenues in 2001 and 2000 varied slightly compared with the prior
year as a result of adjustments and true-ups related to contractual pricing. No
significant declines in the amount of capacity are scheduled until the
termination of the contracts in 2010.
Energy Sales
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour sales for 2001 and the percent change by year were as
follows:
Amount Percent Change
(billions of -------- --------------------------
kilowatt-hours) 2001 2001 2000 1999
- ------------------------------ ---------------------------
Residential 44.5 (3.6)% 6.5% (0.2)%
Commercial 46.9 1.5 6.6 4.0
Industrial 52.9 (6.8) 1.0 1.6
Other 1.0 0.7 2.7 1.6
Total retail 145.3 (3.2) 4.3 1.7
-----
Sales for resale --
Within service area 9.4 (2.0) 1.5 (4.1)
Outside service area 21.4 24.4 33.0 (0.4)
------
Total 176.1 (0.5) 6.4 1.2
==============================================================
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Although the number of residential customers increased 43,000 in 2001, retail
energy sales registered a 3.2 percent decline. This is the first decrease since
1982. Reduced retail sales in 2001 were driven by extremely mild weather and the
sluggish economy, which severely impacted industrial sales. In 2000, the rate of
growth in total retail energy sales was very strong. Residential energy sales
reflected a substantial increase as a result of the hotter-than-normal summer
weather and the increase in customers served. Also in 2000, commercial sales
continued to reflect the strong economy in the Southeast. Energy sales to retail
customers are projected to increase at an average annual rate of 1.8 percent
during the period 2002 through 2012.
Sales to customers outside the service area under long-term contracts for
unit power sales increased 2.7 percent in 2001 and increased 21 percent in 2000.
These changes in sales were influenced by weather -- discussed earlier -- and
fluctuations in prices for oil and natural gas. These are the primary fuel
sources for utilities with which the company has long-term contracts. However,
these fluctuations in energy sales under long-term contracts have minimal
effects on earnings because the energy is generally sold at variable cost.
Expenses
In 2001, operating expenses of $7.5 billion increased only $83 million compared
with the prior year. The moderate increase reflected flat energy sales and
tighter cost containment measures. The costs to produce electricity for the core
business in 2001 increased $96 million. However, non-production operation and
maintenance declined by $23 million.
In 2000, operating expenses of $7.4 billion increased $644 million compared
with the prior year. The costs to produce electricity in 2000 increased by $498
million to meet higher energy requirements. Non-production operation and
maintenance expenses increased $46 million in 2000. Depreciation and
amortization expenses in 2000 increased $89 million, of which $50 million
resulted from additional accelerated amortization by Georgia Power.
Fuel costs constitute the single largest expense for the six electric
utilities. The mix of fuel sources for generation of electricity is determined
primarily by system load, the unit cost of fuel consumed, and the availability
of hydro and nuclear generating units. The amount and sources of generation and
the average cost of fuel per net kilowatt-hour generated -- within the service
area -- were as follows:
2001 2000 1999
- ---------------------------------------------------------------
Total generation
(billions of kilowatt-hours) 174 174 165
Sources of generation
(percent) --
Coal 72 78 78
Nuclear 16 16 17
Oil and gas 9 4 3
Hydro 3 2 2
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.56 1.51 1.45
- ---------------------------------------------------------------
In 2001, fuel and purchased power costs of $3.3 billion increased $54
million. Continued efforts to control energy costs combined with additional
efficient gas-fired generating units helped to hold the increase in fuel expense
to $13 million in 2001.
Total fuel and purchased power costs increased $504 million in 2000 as a
result of 10.6 billion more kilowatt-hours being sold than in 1999. Demand was
met with some 2.5 billion additional kilowatt-hours being purchased and using
generation with higher unit fuel cost than in 1999.
Total interest charges and other financing costs in 2001 decreased $25
million from amounts reported in the previous year. The decline reflected
substantially lower short-term interest rates that offset new financing costs.
Total interest charges and other financing costs in 2000 increased $29 million
reflecting some additional external financing for new generating units.
Effects of Inflation
The operating companies are 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
Southern Company because of the large investment in utility plant with long
economic lives. Conventional accounting for historical cost does not recognize
this economic loss nor the partially offsetting gain that arises through
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
financing facilities with fixed-money obligations such as long-term debt and
preferred securities. Any recognition of inflation by regulatory authorities is
reflected in the rate of return allowed.
Future Earnings Potential
General
The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of Southern
Company's future earnings depends on numerous factors. The two major factors are
the ability of the operating companies to achieve energy sales growth while
containing cost in a more competitive environment and the profitability of the
new competitive market-based wholesale generating facilities being added.
Future earnings for the electricity business in the near term will depend
upon growth in energy sales, which is subject to a number of factors. These
factors include 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 service area.
The operating companies operate as vertically integrated companies providing
electricity to customers within the service area of the southeastern United
States. Prices for electricity provided to retail customers are set by state
public service commissions under cost-based regulatory principles. Retail rates
and earnings are reviewed and adjusted periodically within certain limitations
based on earned return on equity. See Note 3 to the financial statements for
additional information about these and other regulatory matters.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, Southern Company recorded non-cash
income of approximately $124 million in 2001. Future pension income is dependent
on several factors including trust earnings and changes to the plan. For the
operating companies, pension income is a component of the regulated rates and
does not have a significant effect on net income. For more information, see Note
2 to the financial statements.
Southern Company currently receives tax benefits related to investments in
alternative fuel partnerships and leveraged lease agreements for energy
generation, distribution, and transportation assets that contribute
significantly to the economic results for these projects. Changes in Internal
Revenue Service interpretations of existing regulations or challenges to the
company's positions could result in reduced availability or changes in the
timing of such tax benefits. The net income impact of these investments totaled
$52 million, $28 million, and $11 million in 2001, 2000, and 1999, respectively.
See Note 1 to the financial statements under "Leveraged Leases" and Note 6 for
additional information and related income taxes.
Southern 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."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are affected by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers.
Although the Energy Act does not permit retail customer access, it has been a
major catalyst for recent restructuring and consolidations taking place within
the utility industry. Numerous federal and state initiatives are in varying
stages that promote wholesale and retail competition. Among other things, these
initiatives allow customers to choose their electricity provider. Some states
have approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While various restructuring and
competition initiatives have been discussed in Alabama, Florida, Georgia, and
Mississippi, none have been enacted. Enactment would require numerous issues to
be resolved, including significant ones relating to recovery of any stranded
investments, full cost recovery of energy produced, and other issues related to
the energy crisis that occurred in California. As a result of that crisis, many
states have either discontinued or delayed implementation of initiatives
involving retail deregulation.
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
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 Southern Company's electric utilities do not remain low-cost
producers and provide quality service, then energy sales growth could be
limited, and this could significantly erode earnings.
To adapt to a less regulated, more competitive environment, Southern Company
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets, or some combination thereof.
Furthermore, Southern Company may engage in new business ventures that arise
from competitive and regulatory changes in the utility industry. Pursuit of any
of the above strategies, or any combination thereof, may significantly affect
the business operations and financial condition of Southern Company.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to allow holding companies to form exempt wholesale generators and foreign
utilities to sell power largely free from regulation under PUHCA. These entities
are able to own and operate power generating facilities and sell power to
affiliates -- under certain restrictions.
Southern Company is working to maintain and expand its share of wholesale
energy sales in the Southeastern power markets. In January 2001, Southern
Company formed a new subsidiary -- Southern Power Company. This subsidiary
constructs, owns, and manages wholesale generating assets in the Southeast.
Southern Power will be the primary growth engine for Southern Company's
competitive wholesale market-based energy business. By the end of 2003, Southern
Power plans to have approximately 4,700 megawatts of generating capacity in
commercial operation. At December 31, 2001, 800 megawatts are in commercial
operation and some 3,900 megawatts of capacity are under construction.
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
Southern Company explained that it is developing a for-profit RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to
have a material impact on Southern Company's financial statements. The outcome
of this matter cannot now be determined.
Accounting Policies
Critical Policy
Southern Company's significant accounting policies are described in Note 1 to
the financial statements. The company's most critical accounting policy involves
rate regulation. The operating companies are 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 a 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 Standards
Effective January 2001, Southern Company adopted FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended.
Statement No. 133 establishes accounting and reporting standards for derivative
instruments and for hedging activities. This statement requires that certain
derivative instruments be recorded in the balance sheet as either an asset or
liability measured at fair value and that changes in the fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. See Note 1 to the financial statements under "Financial Instruments" for
additional information. The impact on net income in 2001 was not material. An
additional interpretation of Statement No. 133 will result in a change --
effective April 1, 2002 -- in accounting for certain contracts related to fuel
supplies that contain quantity options. These contracts will be accounted for as
derivatives and marked to market. However, due to the existence of specific
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
cost-based fuel recovery clauses for the operating companies, this change is not
expected to have a material impact on net income.
In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. Southern Company adopted Statement No. 142 in January 2002 with no
material impact on the financial statements.
Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. Southern Company has not yet quantified the impact of adopting
Statement No. 143 on its financial statements.
FINANCIAL CONDITION
- ------------------
Overview
Southern Company's financial condition continues to remain strong. In 2001, most
of the operating companies' earnings were at the high end of their respective
allowed range of return on equity. Also, earnings from new business activities
made a solid contribution. These factors drove consolidated net income from
continuing operations to a record $1.12 billion in 2001. The quarterly dividend
declared in January 2002 was 331/2 cents per share, or $1.34 on an annual basis.
Southern Company is committed to a goal of increasing the dividend over time
consistent with growth in earnings. Southern Company's target is to grow
earnings per share at an average annual rate of 5 percent or more. The dividend
payout ratio goal is 75 percent.
Gross property additions to utility plant from continuing operations were
$2.6 billion in 2001. The majority of funds needed for gross property additions
since 1998 has been provided from operating activities. The Consolidated
Statements of Cash Flows provide additional details.
Off-Balance Sheet Financing Arrangements
At December 31, 2001, Southern Company utilized two separate financing
arrangements that are not required to be recorded on the balance sheet. In May
2001, Mississippi Power began the initial 10-year term of an operating lease
agreement signed in 1999 with Escatawpa Funding, Limited Partnership, a special
purpose entity, to use a combined-cycle generating facility located at
Mississippi Power's Plant Daniel. The facility cost approximately $370 million.
The lease provides for a residual value guarantee -- approximately 71 percent of
the completion cost -- by Mississippi Power that is due upon termination of the
lease in certain circumstances. See Note 9 to the financial statements under
"Operating Leases" for additional information regarding this lease.
Southern Power in 2001 entered into a financial arrangement with Westdeutsche
Landesbank Girozentrale (WestLB) that is in effect until September 2002. Under
this agreement, Southern Power may assign up to $125 million in vendor contracts
for equipment to WestLB. For accounting purposes, WestLB is the owner of the
contracts. Southern Power acts as an agent for WestLB and instructs WestLB when
to make payments to the vendors. At December 31, 2001, approximately $47 million
of such vendor equipment contracts had been assigned to WestLB. Southern Power
currently anticipates terminating this arrangement and reacquiring these assets
in the first quarter of 2002.
Credit Rating Risk
Southern Company and its subsidiaries do not have any credit agreements that
would require material changes in payment schedules or terminations as a result
of a credit rating downgrade. There are contracts that could require collateral
- -- but not accelerated payment -- in the event of a credit rating change to
below investment grade. These contracts are primarily for physical electricity
sales, fixed-price physical gas purchases, and agreements covering interest rate
swaps and currency swaps. At December 31, 2001, the maximum potential collateral
requirements under the electricity sale contracts were approximately $230
million. Generally, collateral may be provided for by a Southern Company
guaranty, a letter of credit, or cash. At December 31, 2001, there were no
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
material collateral requirements for the gas purchase contracts or other
financial instrument agreements.
Market Price Risk
Southern Company is exposed to market risks, including changes in interest
rates, currency exchange rates, and certain commodity prices. To manage the
volatility attributable to these exposures, the company nets the exposures to
take advantage of natural offsets and enters into various derivative
transactions for the remaining exposures pursuant to the company's policies in
areas such as counterparty exposure and hedging practices. Company policy is
that derivatives are to be used primarily for hedging purposes. Derivative
positions are monitored using techniques that include market valuation and
sensitivity analysis.
The company's market risk exposures relative to interest rate changes have
not changed materially compared with the previous reporting period. In addition,
the company is not aware of any facts or circumstances that would significantly
affect such exposures in the near term.
If the company sustained a 100 basis point change in interest rates for all
variable rate long-term debt, the change would affect annualized interest
expense by approximately $22 million at December 31, 2001. Based on the
company's overall interest rate exposure at December 31, 2001, including
derivative and other interest rate sensitive instruments, a near-term 100 basis
point change in interest rates would not materially affect the consolidated
financial statements.
Due to cost-based rate regulations, the operating companies have limited
exposure to market volatility in interest rates, commodity fuel prices, and
prices of electricity. To mitigate residual risks relative to movements in
electricity prices for the operating companies, they and Southern Power enter
into fixed price contracts for the purchase and sale of electricity through the
wholesale electricity market and to a lesser extent similar contracts for gas
purchases. Also, some of the operating companies have implemented fuel-hedging
programs at the instruction of their respective public service commissions.
Realized gains and losses are recognized in the income statement as incurred. At
December 31, 2001, exposure from these activities was not material to the
consolidated financial statements. Fair value of changes in energy trading
contracts and year-end valuations are as follows:
Changes During the Year
- ---------------------------------------------------------------
Fair Value
- ---------------------------------------------------------------
(in millions)
Contracts beginning of year $ 1.7
Contracts realized or settled (1.4)
New contracts -
Changes in valuation techniques -
Current period changes 1.0
- --------------------------------------------------------------
Contracts end of year $ 1.3
==============================================================
Source of Year-End Valuation Prices
- --------------------------------------------------------------
Maturity
Total -------------------
Fair Value Year 1 1-3 Years
- --------------------------------------------------------------
(in millions)
Actively quoted $(3.8) $(5.1) $1.3
External sources 5.1 5.1 -
Models and other
methods - - -
- --------------------------------------------------------------
Contracts end of year $ 1.3 $ - $1.3
==============================================================
For additional information, see Note 1 to the financial statements under
"Financial Instruments."
Capital Structure
During 2001, the operating companies issued $1.2 billion of senior notes. The
majority of these proceeds was used to retire long-term debt. The companies
continued to reduce financing costs by retiring higher-cost securities.
Retirements of bonds and senior notes, including maturities, totaled $1.2
billion in 2001, $298 million during 2000, and $1.2 billion during 1999.
Southern Company issued through the company's stock plans 17 million treasury
shares of common stock in 2001. Proceeds were $395 million and were primarily
used to reduce short-term debt. At December 31, 2001, approximately 2 million
treasury shares remain unissued.
At the close of 2001, the company's common stock market value was $25.35 per
share, compared with book value of $11.44 per share. The market-to-book value
ratio was 222 percent at the end of 2001, compared with 212 percent at year-end
2000.
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $2.8 billion for
2002, $2.1 billion for 2003, and $2.3 billion for 2004. Actual construction
costs may vary from this estimate 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.
Southern Company has approximately 4,500 megawatts of new generating capacity
scheduled to be placed in service by 2003. Approximately 3,900 megawatts of
additional new capacity will be dedicated to the wholesale market and owned by
Southern Power. Significant construction of transmission and distribution
facilities and upgrading of generating plants will be continuing.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.4
billion will be required by the end of 2004 for present improvement fund
requirements and maturities of long-term debt. Also, the subsidiaries will
continue to retire higher-cost debt and preferred stock and replace these
obligations with lower-cost capital if market conditions permit.
These capital requirements, lease obligations, and purchase commitments --
discussed in Notes 8 and 9 to the financial statements -- are as follows:
2002 2003 2004
- --------------------------------------------------------------
(in millions)
Bonds -
First mortgage $ 7 $ - $ -
Pollution control 8 - -
Notes 410 1,072 890
Leases -
Capital 4 4 4
Operating 74 71 70
Purchase commitments -
Fuel 2,399 2,185 1,541
Purchased power 97 100 95
- --------------------------------------------------------------
At the beginning of 2002, Southern Company had used $293 million of its
available credit arrangements. Credit arrangements are as follows:
Expires
----------------------------
Total Unused 2002 2003 & Beyond
- --------------------------------------------------------------
(in millions)
$5,423 $5,130 $3,658 $1,472
- --------------------------------------------------------------
Environmental Matters
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power, and the system service company. The complaint alleges violations of the
New Source Review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the operating companies a notice of violation related
to 10 generating facilities, which includes the five facilities mentioned
previously. In early 2000, the EPA filed a motion to amend its complaint to add
the violations alleged in its notice of violation and to add Gulf Power,
Mississippi Power, and Savannah Electric as defendants. The complaint and notice
of violation are similar to those brought against and issued to several other
electric utilities. These complaints and notices of violation allege that the
utilities 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 U.S. District Court
in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in
Georgia and granted the system service company's motion to dismiss on the
grounds that it neither owned nor operated the generating units involved in the
proceedings. The court granted the EPA's motion to add Savannah Electric as a
defendant, but it denied the motion to add Gulf Power and Mississippi Power
based on lack of jurisdiction over those companies. The court directed the EPA
to refile its amended complaint limiting claims to those brought against
Georgia Power and Savannah Electric. The EPA refiled those claims as directed
by the court. Also, the EPA refiled its claims against Alabama Power in U.S.
II-15
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
District Court in Alabama. It has not refiled against Gulf Power, Mississippi
Power, or the system service company. The Alabama Power, Georgia Power, and
Savannah Electric cases have been stayed since the spring of 2001, pending a
ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a
very similar New Source Review enforcement action against the Tennessee Valley
Authority (TVA). The TVA case involves many of the same legal issues raised by
the actions against Alabama Power, Georgia Power, and Savannah Electric. Because
the outcome of the TVA case could have a significant adverse impact on Alabama
Power and Georgia Power, both companies are parties to that case as well. The
U.S. District Court in Alabama has indicated that it will revisit the issue of a
continued stay in April 2002. The U.S. District Court in Georgia is currently
considering a motion by the EPA to reopen the Georgia case. Georgia Power and
Savannah Electric have opposed that motion.
Southern Company believes that its operating companies 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 in any
one of these cases could require substantial capital expenditures that cannot be
determined at this time and could 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.
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company. Reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
were required in two phases. Phase I compliance began in 1995. Southern Company
achieved Phase I compliance at its affected plants by primarily switching to
low-sulfur coal and with some equipment upgrades. Construction expenditures for
Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled
approximately $300 million. Phase II sulfur dioxide compliance was required in
2000. Southern Company used emission allowances and fuel switching to comply
with Phase II requirements. Also, equipment to control nitrogen oxide emissions
was installed on additional system fossil-fired units as necessary to meet Phase
II limits and ozone non-attainment requirements for metropolitan Atlanta through
2000. Compliance for Phase II and initial ozone non-attainment requirements
increased total construction expenditures through 2000 by approximately $100
million.
Respective state plans to address the one-hour ozone non-attainment standards
for the Atlanta and Birmingham areas have been established and must be
implemented in May 2003. Seven generating plants in the Atlanta area and two
plants in the Birmingham area will be affected. Construction expenditures for
compliance with these new rules are currently estimated at approximately $940
million, of which $520 million remains to be spent.
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA. In addition, the Federal District of
Columbia Circuit Court of Appeals is considering other legal challenges to these
standards. A court decision is expected in the spring of 2002. If the standards
are eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued regional nitrogen oxide reduction rules to
the states for implementation. The final rule affects 21 states, including
Alabama and Georgia. Compliance is required by May 31, 2004, for most states,
including Alabama. For Georgia, further rulemaking was required, and proposed
compliance was delayed until May 1, 2005. Additional construction expenditures
for compliance with these new rules are currently estimated at approximately
$190 million.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and the regulations are scheduled to be finalized by the end
of 2004 with implementation to take place around 2007. In January 2001, the EPA
II-16
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional
Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and the utility industry. Generally, this rule affects the operation and
maintenance of electrostatic precipitators and could involve significant
additional ongoing expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
Southern Company must comply with other environmental laws and regulations
that cover the handling and disposal of hazardous waste. Under these various
laws and regulations, the subsidiaries could incur substantial costs to clean up
properties. The subsidiaries conduct studies to determine the extent of any
required cleanup and have recognized in their respective financial statements
costs to clean up known sites. These costs for Southern Company amounted to $1
million in 2001 and $4 million in both 2000 and 1999. Additional sites may
require environmental remediation for which the subsidiaries may be liable for a
portion or all required cleanup costs. See Note 3 to the financial statements
for information regarding Georgia Power's potentially responsible party status
at sites in Georgia.
Several major pieces of environmental legislation are periodically 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 Southern Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, 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 amount and timing of additional equity capital to be raised in 2002 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital can be provided from any combination of
public offerings, private placements, or the company's stock plans.
The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources. However, the type and timing of any financings
- -- if needed -- will depend on market conditions and regulatory approval. In
recent years, financings primarily have utilized unsecured debt and trust
preferred securities.
Southern Power will use both external funds and equity capital from Southern
Company to finance its construction program.
To meet short-term cash needs and contingencies, Southern Company had at the
beginning of 2002 approximately $354 million of cash and cash equivalents and
$5.1 billion of unused credit arrangements with banks.
II-17
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Cautionary Statement Regarding
Forward-Looking Information
Southern Company's 2001 Annual Report includes forward-looking statements in
addition to historical information. Forward-looking information includes, among
other things, statements concerning the strategic goals for Southern Company's
new wholesale business and also Southern Company's goals for dividend payout
ratio, earnings per share, and earnings growth. In some cases, forward-looking
statements can be identified by terminology such as "may," "will," "could,"
"should," "expects," "plans," "anticipates," "believes," "estimates,"
"projects," "predicts," "potential," or "continue" or the negative of these
terms or other comparable terminology. Southern Company cautions that there are
various important factors that could cause actual results to differ materially
from those indicated in the forward-looking statements; accordingly, there can
be no assurance that such indicated results will be realized. These factors
include the impact of recent and future federal and state regulatory change,
including legislative and regulatory initiatives regarding deregulation and
restructuring of the electric utility industry, and also changes in
environmental and other laws and regulations to which Southern Company and its
subsidiaries are subject, as well as changes in application of existing laws
and regulations; current and future litigation, including the pending EPA civil
action against certain Southern Company subsidiaries and the race discrimination
litigation against certain Southern Company subsidiaries; the effects, extent,
and timing of the entry of additional competition in the markets in which
Southern Company's subsidiaries operate; the impact of fluctuations in
commodity prices, interest rates, and customer demand; state and federal rate
regulations; political, legal, and economic conditions and developments in the
United States; the performance of projects undertaken by the non-traditional
business and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets
or businesses, which cannot be assured to be completed or beneficial to Southern
Company or its subsidiaries; the effects of, and changes in, economic conditions
in the areas in which Southern Company's subsidiaries operate; the direct or
indirect effects on Southern Company's business resulting from the terrorist
incidents on September 11, 2001, or any similar such incidents or responses to
such incidents; financial market conditions and the results of financing
efforts; the timing and acceptance of Southern Company's new product and service
offerings; the ability of Southern Company to obtain additional generating
capacity at competitive prices; weather and other natural phenomena; and other
factors discussed elsewhere herein and in other reports (including the Form
10-K) filed from time to time by Southern Company with the Securities and
Exchange Commission.
II-18
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Revenues:
Retail sales $ 8,440 $ 8,600 $8,090
Sales for resale 1,174 977 823
Other revenues 541 489 404
- ------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 10,155 10,066 9,317
- ------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 2,577 2,564 2,328
Purchased power 718 677 409
Other operations 1,852 1,861 1,838
Maintenance 909 852 829
Depreciation and amortization 1,173 1,171 1,139
Taxes other than income taxes 535 536 523
- ------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 7,764 7,661 7,066
- ------------------------------------------------------------------------------------------------------------------------------
Operating Income 2,391 2,405 2,251
Other Income:
Interest income 27 29 30
Other, net 3 (21) (45)
- ------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations
Before Interest and Income Taxes 2,421 2,413 2,236
- ------------------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 557 643 527
Distributions on capital and preferred securities of subsidiaries 169 169 175
Preferred dividends of subsidiaries 18 19 20
- ------------------------------------------------------------------------------------------------------------------------------
Total interest and other 744 831 722
- ------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before Income Taxes 1,677 1,582 1,514
Income taxes 558 588 599
- ------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before
Cumulative Effect of Accounting Change 1,119 994 915
Cumulative effect of accounting change --
less income taxes of less than $1 1 - -
- ------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations 1,120 994 915
Earnings from discontinued operations,
net of income taxes of $93, $86, and $127
for 2001, 2000, and 1999, respectively 142 319 361
- ------------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 1,262 $ 1,313 $1,276
==============================================================================================================================
Common Stock Data:
Earnings per share from continuing operations -
Basic $1.62 $1.52 $1.33
Diluted 1.61 1.52 1.33
Earnings per share including discontinued operations -
Basic $1.83 $2.01 $1.86
Diluted 1.82 2.01 1.86
- ------------------------------------------------------------------------------------------------------------------------------
Average number of shares of common stock outstanding - (in millions)
Basic 689 653 685
Diluted 694 654 686
- ------------------------------------------------------------------------------------------------------------------------------
Cash dividends paid per share of common stock $1.34 $1.34 $1.34
- ------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-19
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Activities:
Consolidated net income $ 1,262 $ 1,313 $ 1,276
Adjustments to reconcile consolidated net income
to net cash provided from operating activities --
Less income from discontinued operations 142 319 361
Depreciation and amortization 1,358 1,337 1,216
Deferred income taxes and investment tax credits (22) 97 10
Other, net (192) 18 118
Changes in certain current assets and liabilities --
Receivables, net 344 (379) (141)
Fossil fuel stock (199) 78 (41)
Materials and supplies (43) (15) (37)
Accounts payable (51) 180 (65)
Other 69 66 244
- ------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities of continuing operations 2,384 2,376 2,219
- ------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (2,617) (2,225) (1,881)
Other (119) (81) (362)
- ------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities of continuing operations (2,736) (2,306) (2,243)
- ------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 223 (275) 831
Proceeds --
Long-term senior notes 1,242 650 840
Other long-term debt 757 93 629
Capital and preferred securities 30 - 250
Common stock 395 910 24
Redemptions --
First mortgage bonds (616) (211) (890)
Other long-term debt (569) (204) (483)
Capital and preferred securities - - (100)
Preferred stock - - (86)
Common stock repurchased - (415) (862)
Payment of common stock dividends (922) (873) (921)
Other (33) (54) (50)
- ------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for)
financing activities of continuing operations 507 (379) (818)
- ------------------------------------------------------------------------------------------------------------------------------
Cash provided from (used for) discontinued operations - 354 684
- ------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 155 45 (158)
Cash and Cash Equivalents at Beginning of Year 199 154 312
- ------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 354 $ 199 $ 154
==============================================================================================================================
Supplemental Cash Flow Information
From Continuing Operations:
Cash paid during the year for --
Interest (net of amount capitalized) $624 $802 $684
Income taxes $721 $666 $656
- ------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-20
CONSOLIDATED BALANCE SHEETS
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(in millions)
Current Assets:
Cash and cash equivalents $ 354 $ 199
Special deposits 23 6
Receivables, less accumulated provisions for uncollectible accounts
of $24 in 2001 and $22 in 2000 1,132 1,312
Under recovered retail fuel clause revenue 280 418
Fossil fuel stock, at average cost 394 195
Materials and supplies, at average cost 550 507
Other 223 188
- -------------------------------------------------------------------------------------------------------------------
Total current assets 2,956 2,825
- -------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 35,813 34,188
Less accumulated depreciation 15,020 14,350
- -------------------------------------------------------------------------------------------------------------------
20,793 19,838
Nuclear fuel, at amortized cost 202 215
Construction work in progress 2,089 1,569
- -------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 23,084 21,622
- -------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Nuclear decommissioning trusts, at fair value 682 690
Net assets of discontinued operations - 3,320
Leveraged leases 655 596
Other 193 161
- -------------------------------------------------------------------------------------------------------------------
Total other property and investments 1,530 4,767
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 924 957
Prepaid pension costs 547 398
Debt expense, being amortized 103 99
Premium on reacquired debt, being amortized 280 280
Other 400 312
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 2,254 2,046
- -------------------------------------------------------------------------------------------------------------------
Total Assets $29,824 $31,260
===================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-21
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity 2001 2000
- -----------------------------------------------------------------------------------------------------------------
(in millions)
Current Liabilities:
Securities due within one year $ 429 $ 67
Notes payable 1,902 1,680
Accounts payable 847 869
Customer deposits 153 140
Taxes accrued --
Income taxes 160 88
Other 193 208
Interest accrued 118 121
Vacation pay accrued 125 119
Other 445 426
- -----------------------------------------------------------------------------------------------------------------
Total current liabilities 4,372 3,718
- -----------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 8,297 7,843
- -----------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,088 4,074
Deferred credits related to income taxes 500 551
Accumulated deferred investment tax credits 634 664
Employee benefits provisions 450 401
Prepaid capacity revenues 41 58
Other 814 647
- ----------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 6,527 6,395
- ----------------------------------------------------------------------------------------------------------------
Company or subsidiary obligated mandatorily redeemable
capital and preferred securities (See accompanying statements) 2,276 2,246
- ----------------------------------------------------------------------------------------------------------------
Cumulative preferred stock of subsidiaries (See accompanying statements) 368 368
- ----------------------------------------------------------------------------------------------------------------
Common stockholders' equity (See accompanying statements) 7,984 10,690
- ----------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $29,824 $31,260
================================================================================================================
Commitments and Contingent Matters (Notes 1, 2, 3, 5, 8, 9, and 10)
- ----------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these balance sheets.
II-22
CONSOLIDATED SATEEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
2003 6.13% to 6.63% $ - $ 325
2004 6.60% - 35
2005 6.07% 2 10
2006 6.50% to 6.90% 45 45
2007 through 2011 6.88% - 50
2021 through 2025 6.88% to 9.00% 437 635
2026 through 2030 6.88% 30 30
- ----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 514 1,130
- ----------------------------------------------------------------------------------------------------------------------------
Long-term senior notes payable --
4.69% to 9.75% due 2002-2005 1,834 766
5.38% to 8.58% due 2006-2009 595 744
6.10% to 7.63% due 2010-2017 305 170
6.38% to 8.12% due 2018-2038 788 793
6.63% to 7.13% due 2039-2048 1,029 1,029
Adjustable rates (1.98% to 3.44% at 1/1/02)
due 2002-2005 1,078 734
- ----------------------------------------------------------------------------------------------------------------------------
Total long-term senior notes payable 5,629 4,236
- ----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.00% to 6.75% due 2005-2026 168 539
Variable rates (1.61% to 1.95% at 1/1/02)
due 2015-2025 90 90
Non-collateralized:
4.20% to 6.75% due 2015-2034 726 406
Variable rates (1.75% to 2.05% at 1/1/02)
due 2011-2037 1,566 1,475
- ----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 2,550 2,510
- ----------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 92 95
- ----------------------------------------------------------------------------------------------------------------------------
Unamortized debt (discount), net (59) (61)
- ----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $443 million) 8,726 7,910
Less amount due within one year 429 67
- ----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 8,297 7,843 43.9% 37.1%
- ----------------------------------------------------------------------------------------------------------------------------
II-23
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Company or Subsidiary Obligated Mandatorily
Redeemable Capital and Preferred Securities:
$25 liquidation value --
6.85% to 7.00% 435 435
7.13% to 7.38% 327 297
7.60% to 7.63% 415 415
7.75% 649 649
8.14% to 8.19% 400 400
Auction rate (3.60% at 1/1/02) 50 50
- ---------------------------------------------------------------------------------------------------------------------------
Total company or subsidiary obligated mandatorily
redeemable capital and preferred securities (annual
distribution requirement -- $170 million) 2,276 2,246 12.0 10.6
- ---------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
4.20% to 7.00% 98 98
$25 par or stated value --
5.20% to 5.83% 200 200
Adjustable and auction rates -- at 1/1/02:
3.10% to 3.56% 70 70
- ---------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock of subsidiaries
(annual dividend requirement -- $18 million) 368 368 1.9 1.7
- ---------------------------------------------------------------------------------------------------------------------------
Common Stockholders' Equity:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Issued -- 2001: 701 million shares
-- 2000: 701 million shares
Treasury -- 2001: 2 million shares
-- 2000: 19 million shares
Par value 3,503 3,503
Paid-in capital 14 3,153
Treasury, at cost (57) (545)
Retained earnings 4,517 4,672
Accumulated other comprehensive income --
From continuing operations 7 -
From discontinued operations - (93)
- ---------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity 7,984 10,690 42.2 50.6
- ---------------------------------------------------------------------------------------------------------------------------
Total Capitalization $18,925 $21,147 100.0% 100.0%
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-24
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report
Accumulated
Other Comprehensive
Common Stock Income From
-------------------------- -----------------------------
Par Paid-In Retained Continuing Discontinued
Value Capital Treasury Earnings Operations Operations Total
- -------------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at December 31, 1998 $3,499 $2,463 $ (58) $3,878 $ - $ 15 $ 9,797
Net income - - - 1,276 - - 1,276
Other comprehensive income - - - - - (107) (107)
Stock issued 4 17 1 - - - 22
Stock repurchased, at cost - - (861) - - - (861)
Cash dividends - - - (921) - - (921)
Other - - (1) (1) - - (2)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 3,503 2,480 (919) 4,232 - (92) 9,204
Net income - - - 1,313 - - 1,313
Other comprehensive income - - - - - (1) (1)
Stock issued - 121 789 - - - 910
Stock repurchased, at cost - - (414) - - - (414)
Cash dividends - - - (873) - - (873)
Other - 552 (1) - - - 551
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 3,503 3,153 (545) 4,672 - (93) 10,690
Net income - - - 1,262 - - 1,262
Other comprehensive income - - - - 7 93 100
Stock issued - - 488 (93) - - 395
Mirant spin off distribution - (3,168) - (391) - - (3,559)
Cash dividends - - - (922) - - (922)
Other - 29 - (11) - - 18
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $3,503 $ 14 $ (57) $4,517 $ 7 $ - $ 7,984
===============================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------
(in millions)
Consolidated Net Income $1,262 $1,313 $1,276
- --------------------------------------------------------------------------------------------------------------------------
Other comprehensive income -- continuing operations:
Changes in fair value of qualifying cash flow hedges, net of tax of $4 7 - -
- --------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income -- continuing operations 7 - -
- --------------------------------------------------------------------------------------------------------------------------
Other comprehensive income -- discontinued operations:
Cumulative effect of accounting change for qualifying hedges, net of tax of $(121) (249) - -
Changes in fair value of qualifying hedges, net of tax of $(51) (104) - -
Less: Reclassification adjustment for amounts
included in net income, net of tax of $29 60 - -
Foreign currency translation adjustments, net of tax of $(22), $(1), and $(58)
for the years 2001, 2000, and 1999, respectively (22) (1) (107)
- --------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income -- discontinued operations (315) (1) (107)
- --------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income $ 954 $1,312 $1,169
==========================================================================================================================
The accompanying notes are an integral part of these statements.
II-25
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2001 Annual Report
1. Summary of Significant Accounting
Policies
General
Southern Company is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern LINC), Southern
Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern
Power), and other direct and indirect subsidiaries. The operating companies --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- provide electric service in four Southeastern states. Contracts
among the operating companies -- related to jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. The system service company provides, at
cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Power was established in 2001 to construct, own, and manage Southern
Company's competitive generation assets and sell electricity at market-based
rates in the wholesale market.
On April 2, 2001, the spin off of Mirant Corporation (Mirant) was completed.
As a result of the spin off, Southern Company's financial statements and related
information reflect Mirant as discontinued operations. For additional
information, see Note 11.
The financial statements reflect Southern Company's investments in the
subsidiaries on a consolidated basis. All material intercompany items have been
eliminated in consolidation. Certain prior years' data presented in the
consolidated financial statements have been reclassified to conform with the
current year presentation.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are
subject to the regulatory provisions of the PUHCA. The operating companies also
are subject to regulation by the FERC and their respective state public service
commissions. The companies follow accounting principles generally accepted in
the United States and comply with the accounting policies and practices
prescribed by their respective commissions. The preparation of financial
statements in conformity with accounting principles generally accepted in the
U.S. requires the use of estimates, and the actual results may differ from those
estimates.
Regulatory Assets and Liabilities
The operating companies are subject to the provisions of Financial Accounting
Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain
Types of Regulation. Regulatory assets represent probable future revenues
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Consolidated Balance Sheets at December 31 relate to the
following:
2001 2000
- ---------------------------------------------------------------
(in millions)
Deferred income tax charges $ 924 $ 957
Premium on reacquired debt 280 280
Department of Energy assessments 39 46
Vacation pay 95 92
Postretirement benefits 28 30
Deferred income tax credits (500) (551)
Accelerated amortization (311) (220)
Storm damage reserves (34) (34)
Other, net 125 121
- ---------------------------------------------------------------
Total $ 646 $ 721
===============================================================
In the event that a portion of a 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 value.
Revenues and Fuel Costs
Revenues are recognized as services are rendered. Unbilled revenues are accrued
at the end of each fiscal period. Fuel costs are expensed as the fuel is used.
Electric rates for the operating companies include provisions to adjust billings
for fluctuations in fuel costs, the energy component of purchased power costs,
and certain other costs. Revenues are adjusted for differences between
II-26
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
recoverable fuel costs and amounts actually recovered in current regulated
rates.
Southern 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 continued 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 $133
million in 2001, $136 million in 2000, and $137 million in 1999. Alabama Power
and Georgia Power have contracts with the U.S. Department of Energy (DOE) that
provide for the permanent disposal of spent nuclear fuel. The DOE failed to
begin disposing of spent nuclear fuel in January 1998 as required by the
contracts, and the companies are pursuing legal remedies against the government
for breach of contract. Sufficient pool storage capacity for spent fuel is
available at Plant Farley to maintain full-core discharge capability until the
refueling outages scheduled for 2006 and 2008 for units 1 and 2, respectively.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to
maintain full-core discharge capability for both units into 2014. At Plant
Hatch, an on-site dry storage facility became operational in 2000. Sufficient
dry storage capacity is believed to be available to continue dry storage
operations at Plant Hatch through the life of the plant. Procurement of on-site
dry storage capacity at Plant Farley is in progress, with the intent to place
the capacity in operation in 2005. Procurement of on-site dry storage capacity
at Plant Vogtle will begin in sufficient time to maintain pool full-core
discharge capability.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is funded in part by
a special assessment on utilities with nuclear plants. This assessment is being
paid over a 15-year period, which began in 1993. This fund will be used by the
DOE for the decontamination and decommissioning of its nuclear fuel enrichment
facilities. The law provides that utilities will recover these payments in the
same manner as any other fuel expense. Alabama Power and Georgia Power -- based
on its ownership interests -- estimate their respective remaining liability at
December 31, 2001, under this law to be approximately $21 million and $16
million. These obligations are recorded in the Consolidated Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.4 percent a year in
2001, 2000, and 1999. When property subject to depreciation is retired or
otherwise disposed of in the normal course of business, its original cost --
together with the cost of removal, less salvage -- is charged to accumulated
depreciation. 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 costs of decommissioning nuclear facilities
and removal of other facilities.
Georgia Power recorded accelerated amortization and depreciation amounting to
$91 million in 2001, $135 million in 2000, and $85 million in 1999. See Note 3
under "Georgia Power Retail Rate Orders" for additional information.
The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial nuclear power reactors to establish a plan for providing, with
reasonable assurance, funds for decommissioning. Alabama Power and Georgia Power
have 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 respective state public service
commissions. 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. Alabama Power and Georgia
Power have 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 a specific facility as of the
site study year, and ultimate cost is the estimate to decommission a specific
facility as of its retirement date. The estimated costs of decommissioning --
both site study costs and ultimate costs -- based on the most current study as
II-27
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
of December 31, 2001, for Alabama Power's Plant Farley and Georgia Power's
ownership interests in plants Hatch and Vogtle were as follows:
Plant Plant Plant
Farley Hatch Vogtle
- ----------------------------------------------------------------
Site study basis (year) 1998 2000 2000
Decommissioning periods:
Beginning year 2017 2014 2027
Completion year 2031 2042 2045
- ----------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $629 $486 $420
Non-radiated structures 60 37 48
- ----------------------------------------------------------------
Total $689 $523 $468
================================================================
(in millions)
Ultimate costs:
Radiated structures $1,868 $1,004 $1,468
Non-radiated structures 178 79 166
- ----------------------------------------------------------------
Total $2,046 $1,083 $1,634
================================================================
Significant assumptions:
Inflation rate 4.5% 4.7% 4.7%
Trust earning rate 7.0 6.5 6.5
- ----------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making these estimates.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 2001 and fund balances were as follows:
Plant Plant Plant
Farley Hatch Vogtle
- -----------------------------------------------------------------
(in millions)
Amount expensed in 2001 $ 18 $ 20 $ 9
Accumulated provisions:
External trust funds,
at fair value $318 $229 $135
Internal reserves 36 20 12
- -----------------------------------------------------------------
Total $354 $249 $147
=================================================================
Alabama Power's decommissioning costs for ratemaking are based on the site
study. Effective January 1, 2002, the Georgia Public Service Commission (GPSC)
decreased Georgia Power's annual provision for decommissioning expenses to $8
million. This amount is based on the NRC generic estimate to decommission the
radioactive portion of the facilities as of 2000. The estimates are $383 million
and $282 million for plants Hatch and Vogtle, respectively. The ultimate costs
associated with the 2000 NRC minimum funding requirements are $823 million and
$1.03 billion for plants Hatch and Vogtle, respectively. Alabama Power and
Georgia Power expect their respective state public service commissions to
periodically review and adjust, if necessary, the amounts collected in rates for
the anticipated cost of decommissioning.
In January 2002, Georgia Power received NRC approval for a 20-year extension
of the license at Plant Hatch, which would permit the operation of units 1 and 2
until 2034 and 2038, respectively. The decommissioning costs disclosed above do
not reflect this extension.
Income Taxes
Southern 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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory
disallowances and impairments. Original cost includes: materials; labor; minor
items of property; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the estimated cost of
funds used during construction. The cost of funds capitalized was $67 million in
2001, $71 million in 2000, and $36 million in 1999. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense as incurred or performed. The cost of replacements of property --
exclusive of minor items of property -- is capitalized.
Leveraged Leases
Southern Company has several leveraged lease agreements -- ranging up to 30
years -- that relate to international energy generation, distribution, and
transportation assets. Southern Company receives federal income tax deductions
for depreciation and amortization and for interest on long-term debt related to
these investments.
II-28
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Southern Company's net investment in leveraged leases consists of the
following at December 31:
2001 2000
- ------------------------------------------------------------------
(in millions)
Net rentals receivable $1,430 $1,430
Unearned income (775) (834)
- ------------------------------------------------------------------
Investment in leveraged leases 655 596
Deferred taxes arising
from leveraged leases (193) (128)
- ------------------------------------------------------------------
Net investment in leveraged leases $ 462 $ 468
==================================================================
A summary of the components of income from leveraged leases is as follows:
2001 2000 1999
- ------------------------------------------------------------------
(in millions)
Pretax leveraged lease income $59 $61 $28
Income tax expense 21 21 10
- ------------------------------------------------------------------
Income from leveraged leases $38 $40 $18
==================================================================
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets for impairment when events or
changes in circumstances indicate that the carrying value of such assets may not
be recoverable. The determination of whether an impairment has occurred is based
on an estimate of undiscounted future cash flows attributable to the assets, as
compared with the carrying value of the assets. If an impairment has occurred,
the amount of the impairment recognized is determined by estimating the fair
value of the assets and recording a provision for loss if the carrying value is
greater than the fair value. For assets identified as held for sale, the
carrying value is compared to the estimated fair value less the cost to sell in
order to determine if an impairment provision is required. Until the assets are
disposed of, their estimated fair value is reevaluated when circumstances or
events change.
Cash and Cash Equivalents
For purposes of the consolidated 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 costs 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.
Comprehensive Income
Comprehensive income -- consisting of net income and changes in the fair value
of marketable securities and qualifying cash flow hedges, net of income taxes --
is presented in the consolidated financial statements. Also, comprehensive
income from discontinued operations includes foreign currency translation
adjustments, net of income taxes. The objective of comprehensive income is to
report a measure of all changes in common stock equity of an enterprise that
result from transactions and other economic events of the period other than
transactions with owners.
Financial Instruments
Effective January 2001, Southern Company adopted FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended. The
impact on net income was immaterial.
Southern Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, and certain
commodity prices. Gains and losses on qualifying hedges are deferred and
recognized either in income or as an adjustment to the carrying amount of the
hedged item when the transaction occurs. At December 31, 2001, Southern Company
had $450 million notional amount of interest rate swaps outstanding with
deferred gains of $12 million.
Southern Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the company's exposure to counterparty credit risk.
The operating companies and Southern Power enter into commodity related
forward and option contracts to limit exposure to changing prices on certain
fuel purchases and electricity purchases and sales. Substantially all of
Southern Company's bulk energy purchases and sales contracts meet the definition
of a derivative under FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities. In many cases, these fuel and electricity
contracts qualify for normal purchase and sale exceptions under Statement No.
133 and are accounted for under the accrual method. Other contracts qualify as
cash flow hedges of anticipated transactions, resulting in the deferral of
related gains and losses, and are recorded in other comprehensive income until
the hedged transactions occur. Any ineffectiveness is recognized currently in
II-29
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
net income. Contracts that do not qualify for the normal purchase and sale
exception and that do not meet the hedge requirements are marked to market
through current period income.
Southern Company has firm purchase commitments for equipment that require
payment in euros. As a hedge against fluctuations in the exchange rate for
euros, the company entered into forward currency swaps. The total notional
amount is 48 million euros maturing in 2002 and 2003. At December 31, 2001, the
gain on these swaps was less than $1 million.
Other Southern Company financial instruments for which the carrying amount
did not equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
- ----------------------------------------------------------------
(in millions)
Long-term debt:
At December 31, 2001 $8,634 $8,693
At December 31, 2000 7,815 7,702
Capital and preferred securities:
At December 31, 2001 2,276 2,282
At December 31, 2000 2,246 2,190
- ----------------------------------------------------------------
The fair values for long-term debt and capital and preferred securities were
based on either closing market price or closing price of comparable instruments.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. Also, Southern Company provides certain medical
care and life insurance benefits for retired employees. The operating companies
fund trusts to the extent required by their respective regulatory commissions.
In late 2000, Southern Company adopted several pension and postretirement
benefit plan changes that had the effect of increasing benefits to both current
and future retirees.
The measurement date for plan assets and obligations is September 30 for each
year. The following disclosures exclude discontinued operations.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
----------------------
2001 2000
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $3,397 $3,248
Service cost 104 96
Interest cost 260 239
Benefits paid (176) (159)
Plan amendments 173 4
Actuarial (gain) loss 2 (31)
- ----------------------------------------------------------------
Balance at end of year $3,760 $3,397
================================================================
Plan Assets
----------------------
2001 2000
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $6,157 $5,266
Actual return on plan assets (889) 1,030
Benefits paid (159) (139)
- ----------------------------------------------------------------
Balance at end of year $5,109 $6,157
================================================================
The accrued pension costs recognized in the Consolidated Balance Sheets were
as follows:
2001 2000
- ------------------------------------------------------------------
(in millions)
Funded status $ 1,349 $ 2,760
Unrecognized transition obligation (51) (63)
Unrecognized prior service cost 269 116
Unrecognized net gain (1,020) (2,415)
- ------------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 547 $ 398
==================================================================
Components of the pension plan's net periodic cost were as follows:
2001 2000 1999
- ----------------------------------------------------------------
(in millions)
Service cost $ 104 $ 96 $ 97
Interest cost 260 239 215
Expected return on
plan assets (423) (384) (348)
Recognized net gain (73) (62) (40)
Net amortization 8 - (2)
- ----------------------------------------------------------------
Net pension cost (income) $(124) $(111) $ (78)
================================================================
II-30
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
----------------------
2001 2000
- -----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,052 $ 980
Service cost 22 18
Interest cost 88 76
Benefits paid (54) (43)
Plan amendments 186 69
Actuarial (gain) loss (55) (48)
- -----------------------------------------------------------------
Balance at end of year $1,239 $1,052
=================================================================
Plan Assets
--------------------
2001 2000
- -----------------------------------------------------------------
(in millions)
Balance at beginning of year $459 $395
Actual return on plan assets (59) 47
Employer contributions 79 59
Benefits paid (54) (42)
- -----------------------------------------------------------------
Balance at end of year $425 $459
=================================================================
The accrued postretirement costs recognized in the Consolidated Balance
Sheets were as follows:
2001 2000
- -----------------------------------------------------------------
(in millions)
Funded status $(814) $(593)
Unrecognized transition obligation 174 189
Unrecognized prior service cost 239 66
Unrecognized net loss (gain) (9) (53)
Fourth quarter contributions 41 35
- -----------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $(369) $(356)
=================================================================
Components of the postretirement plan's net periodic cost were as follows:
2001 2000 1999
- --------------------------------------------------------------
(in millions)
Service cost $ 22 $ 18 $ 21
Interest cost 88 76 68
Expected return on
plan assets (40) (34) (26)
Recognized net gain - - 2
Net amortization 26 18 15
- --------------------------------------------------------------
Net postretirement cost $ 96 $ 78 $ 80
==============================================================
The weighted average rates assumed in the actuarial calculations for both the
pension plan and postretirement benefits plan were:
2001 2000
- -----------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Long-term return on plan assets 8.50 8.50
- -----------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.25
percent for 2001 decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001, as follows:
1 Percent 1 Percent
Increase Decrease
- ------------------------------------------------------------------
(in millions)
Benefit obligation $111 $97
Service and interest costs 10 9
- ------------------------------------------------------------------
Employee Savings Plan
Southern Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $51
million, $49 million, and $46 million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
General
Southern Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on Southern Company's financial condition.
Georgia Power Potentially Responsible Party Status
Georgia Power has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act. Georgia
II-31
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Power has recognized $33 million in cumulative expenses through December 31,
2001 for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia, that is listed on the federal National Priorities List.
Georgia Power has contributed to the removal and remedial investigation and
feasibility study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated. As of December 31, 2001, Georgia
Power had recorded approximately $6 million in cumulative expenses associated
with Georgia Power's agreed-upon share of the removal and remedial investigation
and feasibility study costs for the Brunswick site.
The final outcome of each of these matters cannot now be determined. However,
based on the currently known conditions at these sites and the nature and extent
of Georgia Power's activities relating to these sites, management does not
believe that the company's cumulative liability at these sites would be material
to the financial statements.
Environmental Litigation
On November 3, 1999, the EPA brought a civil action in U.S. District Court in
Georgia against Alabama Power, Georgia Power, and the system service company.
The complaint alleges violations of the New Source Review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in Alabama
and Georgia. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The Clean Air Act authorizes civil penalties
of up to $27,500 per day, per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day.
The EPA concurrently issued to the operating companies a notice of violation
related to 10 generating facilities, which includes the five facilities
mentioned previously. In early 2000, the EPA filed a motion to amend its
complaint to add the violations alleged in its notice of violation and to add
Gulf Power, Mississippi Power, and Savannah Electric as defendants. The
complaint and notice of violation are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution control equipment when performing maintenance and
construction at coal-burning plants constructed or under construction prior to
1978. The U.S. District Court in Georgia granted Alabama Power's motion to
dismiss for lack of jurisdiction and granted the system service company's motion
to dismiss on the grounds that it neither owned nor operated the generating
units involved in the proceedings. The court granted the EPA's motion to add
Savannah Electric as a defendant, but it denied the motion to add Gulf Power and
Mississippi Power based on lack of jurisdiction over those companies. The court
directed the EPA to refile its amended complaint limiting claims to those
brought against Georgia Power and Savannah Electric. The EPA refiled those
claims as directed by the court. Also, the EPA refiled its claims against
Alabama Power in U.S. District Court in Alabama. It has not refiled against
Gulf Power, Mississippi Power, or the system service company.
The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.
Southern Company believes that its operating companies complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. An adverse outcome in any one of these
cases could require substantial capital expenditures that cannot be determined
at this time and could 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.
Mobile Energy Services' Petition for Bankruptcy
Mobile Energy Services Holdings (MESH), a subsidiary of Southern Company, is the
owner and operator of a facility that generates electricity, produces steam, and
processes black liquor as part of a pulp and paper complex in Mobile, Alabama.
On January 14, 1999, MESH filed a petition for Chapter 11 bankruptcy relief in
the U.S. Bankruptcy Court. This action was in response to Kimberly-Clark Tissue
II-32
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Company's (Kimberly-Clark) announcement in May 1998 of plans to close its pulp
mill, effective September 1, 1999. The pulp mill had historically provided 50
percent of MESH's revenues.
As a result of settlement discussions with Kimberly-Clark and MESH's
bondholders, Southern Company recorded in 1999 a $69 million after-tax write
down of its investment in MESH. Southern Company recorded an additional $10
million after-tax write down in 2000. At December 31, 2001, MESH had total
assets of $359 million and senior debt outstanding of $190 million of first
mortgage bonds and $72 million related to tax-exempt bonds. In connection with
the bond financings, Southern Company provided certain limited guarantees, in
lieu of funding debt service and maintenance reserve accounts with cash. As of
December 31, 2001, Southern Company had paid the full $41 million pursuant to
the guarantees. Southern Company continues to have guarantees outstanding of
certain potential environmental and other obligations of MESH that represent a
maximum contingent liability of $19 million at December 31, 2001. Mirant has
agreed to indemnify Southern Company for any future obligations incurred under
such guarantees.
On August 4, 2000, MESH filed a proposed plan of reorganization with the U.S.
Bankruptcy Court. The proposed plan of reorganization was most recently amended
on October 15, 2001. Southern Company expects that approval of a plan of
reorganization would result in either a termination of Southern Company's
ownership interest in MESH or the exchange of all assets of MESH for the
cancellation of securities held by the bondholders but would not affect
Southern Company's continuing guarantee obligations discussed earlier. The final
outcome of this matter cannot now be determined.
California Electricity Markets Litigation
Prior to the spin off of Mirant, Southern Company was named as a defendant in
two lawsuits filed in the superior courts of California alleging that certain
owners of electric generation facilities in California, including Southern
Company, engaged in various unlawful and anticompetitive acts that served to
manipulate wholesale power markets and inflate wholesale electricity prices in
California. One lawsuit naming Southern Company, Mirant, and other generators as
defendants alleged that, as a result of the defendants' conduct, customers paid
approximately $4 billion more for electricity than they otherwise would have and
sought an award of treble damages, as well as other injunctive and equitable
relief. The other suit likewise sought treble damages and equitable relief. The
allegations in the two lawsuits in which Southern Company was named seemed to be
directed to activities of subsidiaries of Mirant. On September 28 and November
6, 2001, the plaintiffs voluntarily dismissed Southern Company without prejudice
from the two lawsuits in which it had been named as a defendant. Prior to being
dismissed, Southern Company had notified Mirant of its claim for indemnification
for costs associated with the lawsuits under the terms of the master separation
agreement that governs the spin off of Mirant. Mirant had undertaken the defense
of the lawsuits. Plaintiffs would not be barred by their own dismissal from
naming Southern Company in some future lawsuit, but management believes that the
likelihood of Southern Company having to pay damages in any such lawsuit is
remote.
Race Discrimination Litigation
On July 28, 2000, a lawsuit alleging race discrimination was filed by three
Georgia Power employees against Georgia Power, Southern Company, and the system
service company in the Superior Court of Fulton County, Georgia. Shortly
thereafter, the lawsuit was removed to the United States District Court for the
Northern District of Georgia. The lawsuit also raised claims on behalf of a
purported class. The plaintiffs seek compensatory and punitive damages in an
unspecified amount, as well as injunctive relief. On August 14, 2000, the
lawsuit was amended to add four more plaintiffs. Also, an additional subsidiary
of Southern Company, Southern Company Energy Solutions, Inc., was named a
defendant.
On October 11, 2001, the district court denied the plaintiffs' motion for
class certification. The plaintiffs filed a motion to reconsider the order
denying class certification, and the court denied the plaintiffs' motion to
reconsider. On December 28, 2001, the plaintiffs filed a petition in the United
States Court of Appeals for the Eleventh Circuit seeking permission to file an
appeal of the October 11 decision. The defendants filed a brief in opposition of
the petition on January 18, 2002. Discovery of the seven named plaintiffs'
individual claims that remain in the case is ongoing. The final outcome of the
case cannot now be determined.
Alabama Power Rate Adjustment Procedures
In November 1982, the Alabama Public Service Commission (APSC) adopted rates
that provide for periodic adjustments based upon Alabama Power'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. Most recently, a 2 percent increase in retail rates was effective in
II-33
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
October 2001, in accordance with the Rate Stabilization Equalization plan. The
rate adjustment procedures allow a return on common equity range of 13 percent
to 14.5 percent and limit increases or decreases in rates to 4 percent in any
calendar year and prohibits two consecutive quarterly adjustments in the same
direction.
In December 1995, the APSC issued an order authorizing Alabama Power to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the company's actual base rate revenues exceed the budgeted revenues. During the
years 2001, 2000, and 1999, Alabama Power did not record any such reductions.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Georgia Power Retail Rate Orders
On December 20, 2001, the GPSC approved a three-year retail rate order for
Georgia Power ending December 31, 2004. Under the terms of the order, earnings
will be evaluated against a retail return on common equity range of 10 percent
to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will
be applied to rate refunds, with the remaining one-third retained by Georgia
Power. Retail rates were decreased by $118 million effective January 1, 2002.
Under a previous three-year order ending December 2001, Georgia Power's
earnings were evaluated against a retail return on common equity range of 10
percent to 12.5 percent. The order further provided for $85 million in each
year, plus up to $50 million of any earnings above the 12.5 percent return
during the second and third years, to be applied to accelerated amortization or
depreciation of assets. Two-thirds of additional earnings above the 12.5 percent
return were applied to rate refunds, with the remaining one-third retained by
Georgia Power. Pursuant to the order, Georgia Power recorded $336 million of
accelerated amortization and interest thereon, which has been credited to a
regulatory liability account as mandated by the GPSC.
Under the new rate order, the accelerated amortization and the interest will
be amortized equally over three years as a credit to expense beginning in 2002.
Effective January 1, 2002, Georgia Power discontinued recording accelerated
depreciation and amortization. Georgia Power will not file for a general base
rate increase unless its projected retail return on common equity falls below 10
percent. Georgia Power is required to file a general rate case on July 1, 2004,
in response to which the GPSC would be expected to determine whether the rate
order should be continued, modified, or discontinued.
In 2000 and 1999, Georgia Power recorded $44 million and $79 million,
respectively, of revenue subject to refund for estimated earnings above 12.5
percent retail return on common equity. Refunds applicable to 2000 and 1999 were
made to customers in 2001 and 2000, respectively.
4. JOINT OWNERSHIP AGREEMENTS
Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and
related facilities jointly with Alabama Electric Cooperative, Inc.
Georgia Power owns undivided interests in plants Vogtle, Hatch, Scherer, and
Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the
Municipal Electric Authority of Georgia, the city of Dalton, Georgia, Florida
Power &Light Company (FP&L), and Jacksonville Electric Authority (JEA). In
addition, Georgia Power has joint ownership agreements with OPC for the Rocky
Mountain facilities and with Florida Power Corporation (FPC) for a combustion
turbine unit at Intercession City, Florida. Southern Power owns an undivided
interest in Stanton Unit A and related facilities jointly with the Orlando
Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power
Agency. The unit is scheduled to go into commercial operation in October 2003.
At December 31, 2001, Alabama Power's and Georgia Power's ownership and
investment (exclusive of nuclear fuel) in jointly owned facilities with the
above entities were as follows:
Jointly Owned Facilities
------------------------------------------
Percent Amount of Accumulated
Ownership Investment Depreciation
------------------------------------------
(in millions)
Plant Vogtle
(nuclear) 45.7% $3,304 $1,793
Plant Hatch
(nuclear) 50.1 881 668
Plant Miller
(coal)
Units 1 and 2 91.8 747 326
Plant Scherer
(coal)
Units 1 and 2 8.4 112 56
Plant Wansley
(coal) 53.5 309 152
Rocky Mountain
(pumped storage) 25.4 169 78
Intercession City
(combustion turbine) 33.3 12 1
Plant Stanton
(combined cycle)
Unit A 65.0 31 -
- -----------------------------------------------------------------
II-34
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Alabama Power, Georgia Power, and Southern Power have contracted to operate
and maintain the jointly owned facilities -- except for the Rocky Mountain
project and Intercession City -- as agents for their respective co-owners. The
companies' proportionate share of their plant operating expenses is included in
the corresponding operating expenses in the Consolidated Statements of Income.
5. LONG-TERM POWER SALES AND LEASE
AGREEMENTS
The operating companies have long-term contractual agreements for the sale and
lease of capacity to certain non-affiliated utilities located outside the
system's service area. These agreements are firm and are related to specific
generating units. Because the energy is generally provided at cost under these
agreements, profitability is primarily affected by capacity revenues.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, and JEA. Under these agreements, approximately 1,500 megawatts of capacity
is scheduled to be sold annually unless reduced by FP&L, FPC, and JEA for the
periods after 2001 with a minimum of three years notice -- until the expiration
of the contracts in 2010. Capacity revenues from unit power sales amounted to
$170 million in 2001, $177 million in 2000, and $174 million in 1999.
Southern Power and Mississippi Power have operating leases for portions of
their generating unit capacity. Capacity revenues from these operating leases
amounted to $53 million in 2001 and $20 million in 2000. These amounts are
included in the financial statements as sales for resale. Minimum future
capacity receipts from noncancelable operating leases as of December 31, 2001,
are as follows:
Year Amounts
- ---- ----------------
(in millions)
2002 $ 64
2003 65
2004 64
2005 23
2006 21
2007 and thereafter 97
- ------------------------------------------------------------------
Total $334
==================================================================
6. INCOME TAXES
At December 31, 2001, the tax-related regulatory assets and liabilities were
$924 million and $500 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized interest. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits. The following tables and disclosures exclude
discontinued operations.
Details of income tax provisions are as follows:
2001 2000 1999
- -----------------------------------------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $477 $421 $504
Deferred (10) 95 11
- -----------------------------------------------------------------
467 516 515
- -----------------------------------------------------------------
State --
Current 103 71 85
Deferred (12) 1 (1)
- -----------------------------------------------------------------
91 72 84
- -----------------------------------------------------------------
Total $558 $588 $599
=================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $3,222 $3,199
Property basis differences 1,059 1,105
Other 739 650
- ---------------------------------------------------------------
Total 5,020 4,954
- ---------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 116 111
Other property basis differences 178 206
Deferred costs 234 190
Pension and other benefits 123 125
Other 304 231
- ---------------------------------------------------------------
Total 955 863
- ---------------------------------------------------------------
Total deferred tax liabilities, net 4,065 4,091
Portion included in current assets
(liabilities), net 23 (17)
- ---------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheets $4,088 $4,074
===============================================================
In accordance with regulatory requirements, deferred investment tax credits
are amortized over the lives of the related property with such amortization
normally applied as a credit to reduce depreciation in the Consolidated
Statements of Income. Credits amortized in this manner amounted to $30 million a
year in 2001, 2000, and 1999. At December 31, 2001, all investment tax credits
available to reduce federal income taxes payable had been utilized.
II-35
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
The provision for income taxes differs from the amount of income taxes
determined by applying the applicable U.S. Federal statutory rate to earnings
before income taxes and preferred dividends of subsidiaries, as a result of the
following:
2001 2000 1999
- ----------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.7 3.4 3.8
Alternative fuel tax credits (4.2) (1.3) (0.7)
Non-deductible book
depreciation 1.7 1.7 1.9
Difference in prior years'
deferred and current tax rate (1.1) (1.3) (1.3)
Other (2.2) (0.8) 0.4
- ----------------------------------------------------------------
Effective income tax rate 32.9% 36.7% 39.1%
================================================================
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. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.
Mirant was included in the consolidated federal tax return through April 2,
2001. Under the terms of the separation agreement, Mirant will indemnify
Southern Company for subsequent assessment of any additional taxes related to
its transactions prior to the spin off.
7. COMMON STOCK
Stock Issued and Repurchased
Southern Company issued 17 million and 5 million treasury shares of common stock
in 2001 and 2000, respectively, through various company stock plans. Proceeds
were $395 million in 2001 and $140 million in 2000. The shares were issued
through various company stock plans. At December 31, 2001, approximately 2
million treasury shares remain unissued.
In December 2000, Southern Company issued 28 million treasury shares of
common stock through a public offering. The offering, which included an
overallotment of 3 million shares, raised some $800 million and was priced at
$28.50 per share. The proceeds were used to repay short-term commercial paper.
In April 1999, Southern Company's Board of Directors approved the repurchase
of up to 50 million shares of Southern Company's common stock over a two-year
period through open market or privately negotiated transactions. Under this
program, 50 million shares were repurchased by February 2000 at an average price
of $25.53 per share.
Shares Reserved
At December 31, 2001, a total of 76 million shares was reserved for issuance
pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside
Directors Stock Plan, and the Omnibus Incentive Compensation Plan (stock option
plan).
Stock Option Plan
Southern Company provides non-qualified stock options to a large segment of its
employees ranging from line management to executives. As of December 31, 2001,
5,622 current and former employees participated in the stock option plan. The
maximum number of shares of common stock that may be issued under this plan may
not exceed 55 million. The prices of options granted to date have been at the
fair market value of the shares on the dates of grant. Options granted to date
become exercisable pro rata over a maximum period of three years from the date
of grant. Options outstanding will expire no later than 10 years after the date
of grant, unless terminated earlier by the Southern Company Board of Directors
in accordance with the plan. Stock option data for the plan has been adjusted to
reflect the Mirant spin off. Activity in 2000 and 2001 for the plan is
summarized below:
Shares Average
Subject Option Price
To Option Per Share
- ----------------------------------------------------------------
Balance at December 31, 1999 13,419,978 $14.97
Options granted 11,042,626 14.67
Options canceled (335,282) 14.87
Options exercised (1,560,695) 13.65
- ----------------------------------------------------------------
Balance at December 31, 2000 22,566,627 14.92
Options granted 13,623,210 20.31
Options canceled (3,397,152) 15.39
Options exercised (3,161,800) 13.83
- ----------------------------------------------------------------
Balance at December 31, 2001 29,630,885 $17.46
================================================================
Shares reserved for future grants:
At December 31, 1999 54,684,999
At December 31, 2000 43,955,368
At December 31, 2001 64,795,653
- ---------------------------------------------------------------
Options exercisable:
At December 31, 2000 9,354,705
At December 31, 2001 11,965,858
- ---------------------------------------------------------------
Southern Company accounts for its stock-based compensation plans in
accordance with Accounting Principles Board Opinion No. 25. Accordingly, no
compensation expense has been recognized.
II-36
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
The following table summarizes information about options outstanding at
December 31, 2001:
Dollar Price
Range of Options
-------------------------
11-15 15-20 20-24
- ----------------------------------------------------------------
Outstanding:
Shares (in thousands) 11,742 12,882 5,007
Average remaining
life (in years) 6.7 7.7 9.1
Average exercise price $14.38 $18.34 $22.43
Exerciseable:
Shares (in thousands) 6,694 5,027 245
Average exercise price $14.17 $17.46 $22.42
- ----------------------------------------------------------------
The estimated fair values of stock options granted in 2001, 2000, and 1999
were derived using the Black-Scholes stock option pricing model. The following
table shows the assumptions and the weighted average fair values of stock
options:
2001 2000 1999
- ------------------------------------------------------------------
Interest rate 4.8% 6.7% 5.8%
Average expected life of
stock options (in years) 4.3 4.0 3.7
Expected volatility of
common stock 25.4% 20.9% 20.7%
Expected annual dividends
on common stock $1.34 $1.34 $1.34
Weighted average fair value
of stock options granted $2.82 $3.36 $4.61
- ------------------------------------------------------------------
The pro forma impact of fair-value accounting for options granted on earnings
is as follows:
Net Earnings
Year Income Per Share
- ---- -------------- -------------
(in millions) (cents)
2001 $17 2.4
2000 8 1.3
1999 5 0.7
- -----------------------------------------------------------------
Diluted Earnings Per Share
For Southern Company, the only difference in computing basic and diluted
earnings per share is attributable to outstanding options under the stock option
plan. The effect of the stock options was determined using the treasury stock
method. Shares used to compute diluted earnings per share are as follows:
Average Common Stock Shares
--------------------------------
2001 2000 1999
- ----------------------------------------------------------------
(in thousands)
As reported shares 689,352 653,087 685,163
Effect of options 4,191 1,018 530
- ----------------------------------------------------------------
Diluted shares 693,543 654,105 685,693
================================================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 2001, consolidated retained earnings included
$3.4 billion of undistributed retained earnings of the subsidiaries. Of this
amount, $2.1 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures.
However, Georgia Power expects to discharge its first mortgage bond indenture in
early 2002 and to be released from all indenture requirements. The $2.1 billion
restriction includes $1.0 billion for Georgia Power under the current indenture
requirements.
8. FINANCING
Capital and Preferred Securities
Company or subsidiary obligated mandatorily redeemable capital and preferred
securities have been issued by special purpose financing entities of Southern
Company and its subsidiaries. Substantially all the assets of these special
financing entities are junior subordinated notes issued by the related company
seeking financing. Each of these companies considers that the mechanisms and
obligations relating to the capital or preferred securities issued for its
benefit, taken together, constitute a full and unconditional guarantee by it of
the respective special financing entities' payment obligations with respect to
the capital or preferred securities. At December 31, 2001, capital securities of
$950 million and preferred securities of $1.3 billion were outstanding and
recognized in the Consolidated Balance Sheets. Southern Company guarantees the
notes related to $950 million of capital or preferred securities issued on its
behalf.
II-37
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Long-Term Debt Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
2001 2000
- -----------------------------------------------------------------
(in millions)
Bond improvement fund requirements $ 5 $11
Less:
Portion to be satisfied by certifying
property additions 1 11
- -----------------------------------------------------------------
Cash requirements 4 -
First mortgage bond maturities
and redemptions 3 -
Other long-term debt maturities 422 67
- -----------------------------------------------------------------
Total $429 $67
=================================================================
The first mortgage bond improvement fund requirements amount to 1 percent of
each outstanding series of bonds authenticated under the indentures prior to
January 1 of each year, other than those issued to collateralize pollution
control revenue bonds and other obligations. The requirements may be satisfied
by depositing cash or reacquiring bonds, or by pledging additional property
equal to 1662/3 percent of such requirements.
With respect to the collateralized pollution control revenue bonds, the
operating companies have authenticated and delivered to trustees a like
principal amount of first mortgage bonds as security for obligations under
installment sale or loan agreements. The principal and interest on the first
mortgage bonds will be payable only in the event of default under the
agreements.
Improvement fund requirements and/or serial maturities through 2006
applicable to total long-term debt are as follows: $429 million in 2002; $1.1
billion in 2003; $894 million in 2004; $399 million in 2005; and $226 million in
2006.
Assets Subject to Lien
Each of Southern Company's subsidiaries is organized as a legal entity, separate
and apart from Southern Company and its other subsidiaries. The subsidiary
companies' mortgages, which secure the first mortgage bonds issued by the
companies, constitute a direct first lien on substantially all of the companies'
respective fixed property and franchises. Georgia Power expects to discharge its
mortgage in early 2002 and that the lien will be removed. There are no
agreements or other arrangements among the subsidiary companies under which the
assets of one company have been pledged or otherwise made available to satisfy
obligations of Southern Company or any of its other subsidiaries.
Bank Credit Arrangements
At the beginning of 2002, unused credit arrangements with banks totaled $5.1
billion, of which $3.7 billion expires during 2002, $500 million expires during
2003, and $900 million expires during 2004. The following table outlines the
credit arrangements by company:
Amount of Credit
----------------------------
Expires
---------------
2003 &
Company Total Unused 2002 beyond
- --------------------------------------------------------------
(in millions)
Alabama Power $ 964 $ 964 $ 574 $ 390
Georgia Power 1,765 1,765 1,265 500
Gulf Power 103 103 103 -
Mississippi Power 115 115 110 5
Savannah Electric 66 66 46 20
Southern Company 1,500 1,500 1,500 -
Southern Power 850 557 - 557
Other 60 60 60 -
- --------------------------------------------------------------
Total $5,423 $5,130 $3,658 $1,472
==============================================================
Approximately $2.9 billion of the credit facilities expiring in 2002 allows
for term loans ranging from one to three years. Most of the agreements include
stated borrowing rates but also allow for competitive bid loans.
All of the credit arrangements require payment of commitment fees based on
the unused portion of the commitments or the maintenance of compensating
balances with the banks. These balances are not legally restricted from
withdrawal. Included in the $5.1 billion of unused credit arrangements is $4.8
billion of syndicated credit arrangements that require the payment of agent
fees.
A portion of the $5.1 billion unused credit with banks is allocated to
provide liquidity support to the companies' variable rate pollution control
bonds. The amount of variable rate pollution control bonds requiring liquidity
support as of December 31, 2001 was $1.6 billion.
Southern Company and the operating companies borrow through commercial paper
programs that have the liquidity support of committed bank credit arrangements.
In addition, the companies from time to time borrow under uncommitted lines of
credit with banks. The amount of commercial paper outstanding at December 31,
2001 was $1.8 billion.
II-38
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
9. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently
estimated to total $2.8 billion in 2002, $2.1 billion in 2003, and $2.3 billion
in 2004. The construction programs are subject to periodic review and revision,
and actual construction costs may vary from the above estimates because of
numerous factors. These factors include: changes in business conditions;
acquisition of additional generating assets; revised load growth estimates;
changes in environmental regulations; changes in existing nuclear plants to meet
new regulatory requirements; increasing costs of labor, equipment, and
materials; and cost of capital. At December 31, 2001, significant purchase
commitments were outstanding in connection with the construction program.
Southern Company has approximately 4,500 megawatts of additional generating
capacity scheduled to be placed in service by 2003, of which 3,900 megawatts
will be competitive generation assets.
See Management's Discussion and Analysis under "Environmental Matters" for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of the generating plants, Southern
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.
Natural gas purchases are based on various indices at the time of delivery;
therefore, only the volume commitments are firm and disclosed in the following
chart. Also, Southern Company has entered into various long-term commitments for
the purchase of electricity. Total estimated minimum long-term obligations at
December 31, 2001, were as follows:
Natural
Gas Purchased
Year MMBtu Fuel Power
- ---- ------------ ---------------------
(in millions) (in millions)
2002 163,595 $ 2,399 $ 97
2003 188,245 2,185 100
2004 118,245 1,541 95
2005 66,390 1,218 95
2006 49,085 1,155 95
2007 and thereafter 18,120 3,627 879
- ---------------------------------------------------------------
Total commitments 603,680 $12,125 $1,361
===============================================================
Operating Leases
In May 2001, Mississippi Power began the initial 10-year term of a lease
agreement signed in 1999 for a combined cycle generating facility built at Plant
Daniel. The facility cost approximately $370 million. The lease provides for a
residual value guarantee -- approximately 71 percent of the completion cost --
by Mississippi Power that is due upon termination of the lease in certain
circumstances. The lease also includes purchase and renewal options. Upon
termination of the lease, Mississippi Power may either exercise its purchase
option of the facility or allow it to be sold to a third party. Mississippi
Power expects the fair market value of the leased facility to substantially
reduce or eliminate its payment under the residual value guarantee. The amount
of future minimum operating lease payments exclusive of any payment related to
this guarantee will be approximately $25 million annually during the initial
term.
Southern Company has other operating lease agreements with various terms and
expiration dates. Total operating lease expenses were $64 million, $42 million,
and $35 million for 2001, 2000, and 1999, respectively. At December 31, 2001,
estimated minimum rental commitments for noncancelable operating leases were as
follows:
Year Amounts
- ---- --------------
(in millions)
2002 $ 74
2003 71
2004 70
2005 66
2006 58
2007 and thereafter 317
- ---------------------------------------------------------------
Total minimum payments $656
===============================================================
In addition to the above rental commitments, Alabama Power and Georgia Power
have obligations upon expiration of certain rail car leases with respect to the
residual value of the leased property. These leases expire in 2004, 2006, and
2010, and the maximum obligations are $39 million, $66 million, and $40 million,
respectively. At the termination of the leases, the lessee may either exercise
its purchase option or the property can be sold to a third party. Alabama Power
and Georgia Power expect that the fair market value of the leased property would
substantially reduce or eliminate the payments under the residual value
obligations.
II-39
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Guarantees
Southern Company has made separate guarantees to certain counterparties
regarding performance of contractual commitments by Mirant's trading and
marketing subsidiaries. At December 31, 2001, the total original notional amount
of guarantees was $53 million, all of which will expire by 2007. Estimated fair
value of these net contractual commitments outstanding was approximately $25
million. Under the terms of the separation agreement, Mirant may not enter into
any new commitments under these guarantees after the spin off date. Based upon a
statistical analysis of credit risk, Southern Company's potential exposure under
these contractual commitments would not materially differ from the estimated
fair value.
Mirant will pay Southern Company a fee of 1 percent annually on the average
aggregate maximum principal amount of all guarantees outstanding until they are
replaced or expire. Mirant must use reasonable efforts to release Southern
Company from all such support arrangements and will indemnify Southern Company
for any obligations incurred.
10. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia Power
maintain agreements of indemnity with the NRC that, together with private
insurance, cover third-party liability arising from any nuclear incident
occurring at the companies' nuclear power plants. The act provides funds up to
$9.5 billion for public liability claims that could arise from a single nuclear
incident. Each nuclear plant is insured against this liability to a maximum of
$200 million by American Nuclear Insurers (ANI), with the remaining coverage
provided by a mandatory program of deferred premiums that could be assessed,
after a nuclear incident, against all owners of nuclear reactors. A 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 Alabama Power and Georgia Power -- based on
its ownership and buyback interests -- is $176 million and $178 million,
respectively, per incident, but not more than an aggregate of $20 million per
company to be paid for each incident in any one year.
Alabama Power and Georgia Power are members 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, both companies have policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years.
Under each of the NEIL policies, members are subject to assessments if losses
each year exceed the accumulated funds available to the insurer under that
policy. The current maximum annual assessments for Alabama Power and Georgia
Power under the three NEIL policies would be $35 million and $39 million,
respectively.
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power plants would be
covered under their insurance. However, both companies revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12-month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies shall be
dedicated first for the sole purpose of placing the reactor in a safe and stable
condition after an accident. Any remaining proceeds are to be applied next
toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the company or
to its bond trustees as may be appropriate under the policies and applicable
trust indentures.
All retrospective assessments -- whether generated for liability, property,
or replacement power -- may be subject to applicable state premium taxes.
II-40
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
11. DISCOUNTINUED OPERATIONS
In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant and its intentions to spin off the remaining ownership of
Mirant to Southern Company stockholders within 12 months of the initial stock
offering. On October 2, 2000, Mirant completed its initial public offering of
66.7 million shares of common stock priced at $22 per share. This represented
19.7 percent of the 338.7 million shares outstanding. As a result of the stock
offering, Southern Company recorded a $560 million increase in paid-in capital
with no gain or loss being recognized.
On February 19, 2001, the Southern Company Board of Directors approved the
spin off of its remaining ownership of 272 million Mirant shares. On April 2,
2001, the tax-free distribution of Mirant shares was completed at a ratio of
approximately 0.4 for every share of Southern Company common stock held at
record date.
The distribution resulted in charges of approximately $3.2 billion and $0.4
billion to Southern Company's paid-in capital and retained earnings,
respectively. The distribution was treated as a non-cash transaction for
purposes of the statement of cash flows.
As a result of the spin off, Southern Company's financial statements reflect
Mirant's results of operations, balance sheets, and cash flows as discontinued
operations. Certain amounts in the cash flows related to intercompany
eliminations for 2000 and 1999 have been reclassified from cash provided from
operating activities to cash used for discontinued operations.
Summarized financial information for the discontinued operations is as
follows at December 31:
2001 2000 1999
- -----------------------------------------------------------------
(in millions)
Revenues $8,182 $13,315 $2,265
Income taxes 93 86 127
Net income 142 319 361
- -----------------------------------------------------------------
2000
- -----------------------------------------------------------------
(in millions)
Current assets $ 9,057
Total assets 22,377
Current liabilities 9,726
Total liabilities 17,585
Minority and other interests 1,472
Net assets of
discontinued operations 3,320
- -----------------------------------------------------------------
12. SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segment is the sale of electricity in the
Southeast by the five operating companies and Southern Power. Net income and
total assets for discontinued operations are included in the reconciling
eliminations column. The all other category includes parent Southern Company,
which does not allocate operating expenses to business segments. Also, this
category includes segments below the quantitative threshold for separate
disclosure. These segments include telecommunications, energy products and
services, and leasing and financing services. Intersegment revenues are not
material. Financial data for business segments and products and services are as
follows:
Business Segments
Electric All Reconciling
Year Utilities Other Eliminations Consolidated
- ---- -----------------------------------------------------------------------------------
(in millions)
2001
- -----
Operating revenues $ 9,906 $ 267 $ (18) $10,155
Depreciation and amortization 1,144 29 - 1,173
Interest income 21 8 (2) 27
Interest expense 591 137 (2) 726
Income taxes 702 (144) - 558
Segment net income (loss) 1,149 (30) 143 1,262
Total assets 29,389 2,420 (1,985) 29,824
Gross property additions 2,565 52 - 2,617
- ----------------------------------------------------------------------------------------------------------------------------
II-41
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
Electric All Reconciling
Year Utilities Other Eliminations Consolidated
- ----- ------------------------------------------------------------------------------------
(in millions)
2000
- ----
Operating revenues $ 9,860 $ 246 $ (40) $10,066
Depreciation and amortization 1,135 36 - 1,171
Interest income 21 7 1 29
Interest expense 615 197 - 812
Income taxes 703 (115) - 588
Segment net income (loss) 1,109 (115) 319 1,313
Total assets 26,820 2,200 2,240 31,260
Gross property additions 2,199 26 - 2,225
- ----------------------------------------------------------------------------------------------------------------------------
Electric All Reconciling
Year Utilities Other Eliminations Consolidated
- ---- ------------------------------------------------------------------------------------
(in millions)
1999
- ----
Operating revenues $ 9,125 $ 221 $ (29) $ 9,317
Depreciation and amortization 1,046 93 - 1,139
Interest income 23 5 2 30
Interest expense 585 155 (38) 702
Income taxes 675 76 - 599
Segment net income (loss) 1,073 (158) 361 1,276
Total assets 25,336 2,127 1,828 29,291
Gross property additions 1,854 27 - 1,881
- ----------------------------------------------------------------------------------------------------------------------------
Products and Services
Electric Utilities Revenues
------------------------------------------------------------------------------------
Year Retail Wholesale Other Total
- ---- ------------------------------------------------------------------------------------
(in millions)
2001 $8,440 $1,174 $292 $9,906
2000 8,600 977 283 9,860
1999 8,090 823 212 9,125
- ------------------------------------------------------------------------------------------------------------------------
13. QUARTERLY FINANCIAL INFORMATION FOR CONTINUING OPERATIONS (UNAUDITED)
Summarized quarterly financial data for 2001 and 2000 are as follows:
Per Common Share (Note)
-----------------------------------------------------
Operating Operating Consolidated Basic Price Range
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
- -------------- ------------------------------------ -----------------------------------------------------
(in millions)
March 2001 $2,270 $475 $180 $0.26 $0.335 $21.650 $16.152
June 2001 2,561 585 270 0.40 0.335 23.880 20.890
September 2001 3,165 998 554 0.80 0.335 26.000 22.050
December 2001 2,159 333 116 0.16 0.335 25.980 22.300
March 2000 $2,052 $ 428 $151 $0.23 $0.335 $25.875 $20.375
June 2000 2,522 598 256 0.39 0.335 27.875 21.688
September 2000 3,198 1,039 523 0.81 0.335 35.000 23.406
December 2000 2,294 340 64 0.09 0.335 33.880 27.500
- -----------------------------------------------------------------------------------------------------------------------------
Southern Company's business is influenced by seasonal weather conditions.
Note: Market price data in 2001 declined as a result of the Mirant spin off.
II-42
Selected Consolidated Financial and Operating Data 1997-2001
Southern Company and Subsidiary Companies 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $10,155 $10,066 $9,317 $9,499 $8,774
Total Assets (in millions) $29,824 $31,260 $29,291 $28,723 $27,898
Gross Property Additions (in millions) $2,617 $2,225 $1,881 $1,356 $1,138
Return on Average Common Equity (percent) 13.51 13.20 13.43 10.04 10.30
Cash Dividends Paid Per Share of Common Stock $1.34 $1.34 $1.34 $1.34 $1.30
- -----------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income (in millions):
Continuing operations $1,120 $ 994 $ 915 $986 $990
Discontinued operations 142 319 361 (9) (18)
- -----------------------------------------------------------------------------------------------------------------------------
Total $1,262 $1,313 $1,276 $977 $972
=============================================================================================================================
Earnings Per Share From Continuing Operations --
Basic $1.62 $1.52 $1.33 $1.41 $1.45
Diluted 1.61 1.52 1.33 1.41 1.45
Earnings Per Share Including Discontinued Operations --
Basic $1.83 $2.01 $1.86 $1.40 $1.42
Diluted 1.82 2.01 1.86 1.40 1.42
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $ 7,984 $10,690 $ 9,204 $ 9,797 $ 9,647
Preferred stock and securities 2,644 2,614 2,615 2,465 2,155
Long-term debt 8,297 7,843 7,251 6,505 6,347
- -----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $18,925 $21,147 $19,070 $18,767 $18,149
=============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 42.2 50.6 48.3 52.2 53.2
Preferred stock and securities 13.9 12.3 13.7 13.1 11.9
Long-term debt 43.9 37.1 38.0 34.7 34.9
- -----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0 100.0 100.0
=============================================================================================================================
Other Common Stock Data (Note):
Book value per share (year-end) $11.44 $15.69 $13.82 $14.04 $13.91
Market price per share:
High $26.000 $35.000 $29.625 $31.563 $26.250
Low 16.152 20.375 22.063 23.938 19.875
Close 25.350 33.250 23.500 29.063 25.875
Market-to-book ratio (year-end) (percent) 221.6 211.9 170.0 207.0 186.0
Price-earnings ratio (year-end) (times) 15.6 16.5 12.6 20.8 18.2
Dividends paid (in millions) $922 $873 $921 $933 $889
Dividend yield (year-end) (percent) 5.3 4.0 5.7 4.6 5.0
Dividend payout ratio (percent) 82.4 66.5 72.2 95.6 91.5
Shares outstanding (in thousands):
Average 689,352 653,087 685,163 696,944 685,033
Year-end 698,344 681,158 665,796 697,747 693,423
Stockholders of record (year-end) 150,242 160,116 174,179 187,053 200,508
- -----------------------------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 3,441 3,398 3,339 3,277 3,220
Commercial 539 527 513 497 479
Industrial 14 14 15 15 16
Other 4 5 4 5 5
- -----------------------------------------------------------------------------------------------------------------------------
Total 3,998 3,944 3,871 3,794 3,720
=============================================================================================================================
Employees (year-end) 26,122 26,021 26,269 25,206 24,682
- -----------------------------------------------------------------------------------------------------------------------------
Note: Common stock data in 2001 declined as a result of the Mirant spin off.
II-43
Selected Consolidated Financial and Operating Data 1997-2001 (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $ 3,247 $ 3,361 $3,107 $3,167 $2,836
Commercial 2,966 2,918 2,745 2,766 2,594
Industrial 2,144 2,289 2,238 2,268 2,138
Other 83 32 - 79 77
- ------------------------------------------------------------------------------------------------------------------------------------
Total retail 8,440 8,600 8,090 8,280 7,645
Sales for resale within service area 338 377 350 374 376
Sales for resale outside service area 836 600 473 522 510
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 9,614 9,577 8,913 9,176 8,531
Other revenues 541 489 404 323 243
- ------------------------------------------------------------------------------------------------------------------------------------
Total $10,155 $10,066 $9,317 $9,499 $8,774
====================================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 44,538 46,213 43,402 43,503 39,217
Commercial 46,939 46,249 43,387 41,737 38,926
Industrial 52,891 56,746 56,210 55,331 54,196
Other 977 970 945 929 903
- ------------------------------------------------------------------------------------------------------------------------------------
Total retail 145,345 150,178 143,944 141,500 133,242
Sales for resale within service area 9,388 9,579 9,440 9,847 9,884
Sales for resale outside service area 21,380 17,190 12,929 12,988 13,761
- ------------------------------------------------------------------------------------------------------------------------------------
Total 176,113 176,947 166,313 164,335 156,887
====================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.29 7.27 7.16 7.28 7.23
Commercial 6.32 6.31 6.33 6.63 6.66
Industrial 4.05 4.03 3.98 4.10 3.95
Total retail 5.81 5.73 5.62 5.85 5.74
Sales for resale 3.82 3.65 3.68 3.92 3.75
Total sales 5.46 5.41 5.36 5.58 5.44
Average Annual Kilowatt-Hour
Use Per Residential Customer 13,014 13,702 13,107 13,379 12,296
Average Annual Revenue Per Residential Customer $948.83 $996.44 $938.39 $973.94 $889.29
Plant Nameplate Capacity Owned (year-end) (megawatts) 34,579 32,807 31,425 31,161 31,146
Maximum Peak-Hour Demand (megawatts):
Winter 26,272 26,370 25,203 21,108 22,969
Summer 29,700 31,359 30,578 28,934 27,334
System Reserve Margin (at peak) (percent) 19.3 8.1 8.5 12.8 15.0
Annual Load Factor (percent) 62.0 60.2 59.2 60.0 59.4
Plant Availability (percent):
Fossil-steam 88.1 86.8 83.3 85.2 88.2
Nuclear 90.8 90.5 89.9 87.8 88.8
- ------------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 67.5 72.3 73.1 72.8 74.7
Nuclear 15.2 15.1 15.7 15.4 16.5
Hydro 2.6 1.5 2.3 3.9 4.3
Oil and gas 8.4 4.0 2.8 3.3 1.7
Purchased power 6.3 7.1 6.1 4.6 2.8
- ------------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
====================================================================================================================================
II-44
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-45
MANAGEMENT'S REPORT
Alabama Power Company 2001 Annual Report
The management of Alabama Power Company has prepared -- and is responsible for
- -- the financial statements and related information included in this report.
These statements were prepared in accordance with accounting principles
generally accepted in the United States and necessarily include amounts that are
based on the best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of four independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Alabama Power Company in conformity with accounting principles generally
accepted in the United States.
/s/Charles D. McCrary
Charles D. McCrary
President
and Chief Executive Officer
/s/William B. Hutchins, III
William B. Hutchins, III
Executive Vice President,
Chief Financial Officer, and Treasurer
February 13, 2002
II-46
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary
of Southern Company) as of December 31, 2001 and 2000, and the related
statements of income, common stockholder's equity, and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements (pages II-58 through II-76)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Alabama Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 13, 2002
II-47
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 2001 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 2001 net income after dividends on preferred stock was
$387 million, representing a $33 million (7.9 percent) decrease from the prior
year. This decline is primarily attributable to a decrease in territorial energy
sales as a result of an economic downturn and milder temperatures.
In 2000 earnings were $420 million, representing a 5 percent increase from
the prior year. This improvement was primarily attributable to an increase in
territorial sales partially offset by increased non-fuel operating expenses.
The return on average common equity for 2001 was 11.89 percent compared to
13.58 percent in 2000 and 13.85 percent in 1999.
Revenues
Operating revenues for 2001 were $3.6 billion, reflecting a decrease from 2000.
The following table summarizes the principal factors that have affected
operating revenues for the past two years:
Increase (Decrease)
Amount From Prior Year
--------------------------------------
2001 2001 2000
- -----------------------------------------------------------------
(in thousands)
Retail --
Base revenues $2,033,814 $ (75,125) $ 80,264
Fuel cost recovery
and other 713,859 (129,909) 61,326
- -----------------------------------------------------------------
Total retail 2,747,673 (205,034) 141,590
- -----------------------------------------------------------------
Sales for resale --
Non-affiliates 485,974 24,244 46,353
Affiliates 245,189 78,970 73,780
- -----------------------------------------------------------------
Total sales for resale 731,163 103,214 120,133
Other operating
revenues 107,554 20,749 20,264
- -----------------------------------------------------------------
Total operating
revenues $3,586,390 $ (81,071) $281,987
=================================================================
Percent change (2.21)% 8.33%
- -----------------------------------------------------------------
Retail revenues of $2.7 billion in 2001 decreased
$205 million (6.9 percent) from the prior year, compared with an increase of
$142 million (5 percent) in 2000. The primary contributors to the decrease in
revenues in 2001 were the negative impact of milder temperatures on energy
sales, an economic downturn in the Company's service territory, and a decrease
in fuel revenues. Fuel revenues have no effect on net income because they
represent the recording of revenues to offset fuel expenses. Fuel rates billed
to customers are designed to fully recover fluctuating fuel costs over a period
of time. Lower natural gas prices, an increased fuel rate, and increased hydro
production combined with decreased costs of purchased power have resulted in a
$154 million (65 percent) reduction in under-recovered fuel costs at December
31, 2001 compared with the prior year. The Company expects to continue to reduce
the balance of $83 million during 2002.
II-48
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
Other operating revenues in 2001 increased $21 million (23.9 percent) over
2000. This increase is primarily attributed to increased steam sales in
conjunction with the operation of the Company's co-generation facilities, fuel
sales, and rent from electric property. Since co-generation steam revenues are
generally offset by fuel expenses, these revenues did not have a significant
impact on earnings.
The $20 million (30.5 percent) increase in other operating revenues in 2000
as compared to 1999 was due primarily to an increase in steam sales in
conjunction with the operation of the Company's co-generation facilities.
Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy energy and
energy sold under short-term contracts are also sold for resale outside the
service area. Revenues from long-term power contracts have both a capacity and
energy component. Capacity revenues reflect the recovery of fixed costs and a
return on investment under the contracts. Energy is generally sold at variable
cost. These capacity and energy components of the unit power contracts were as
follows:
2001 2000 1999
-------------------------------------------
(in millions)
Capacity $125 $127 $122
Energy 134 128 112
------------------------------------------------------------
Total $259 $255 $234
============================================================
Capacity revenues from non-affiliates were relatively unchanged in 2001
compared to the prior two years. There are no scheduled declines in capacity
until the termination of the contracts in 2010.
Revenues from sales to affiliated companies within the Southern electric
system, as well as purchases of energy, will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These transactions did not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:
KWH Percent Change
----------------------------------------
2001 2001 2000
----------------------------------------
(millions)
Residential 15,881 (5.3)% 6.8%
Commercial 12,799 (1.5) 5.5
Industrial 20,460 (7.4) 0.7
Other 198 (3.9) 2.3
------------
Total retail 49,338 (5.2) 3.8
Sales for resale -
Non-affiliates 15,278 2.9 19.4
Affiliates 8,843 64.7 6.7
------------
Total 73,459 1.6 6.9
- -----------------------------------------------------------------
Retail energy sales in 2001 decreased by 5.2 percent due to milder
temperatures and an economic downturn in the Company's service area. This was
offset by an increase in sales for resale to affiliates. Increased operation of
the Company's combined cycle facilities due to lower natural gas prices and an
increase in the Company's combined cycle capacity contributed to the increase in
sales for resale.
The increase in 2000 retail energy sales was primarily due to the strength
of business and economic conditions in the Company's service area. Residential
energy sales experienced a 6.8 percent increase over the prior year primarily as
a result of warmer summer temperatures and cold winter weather conditions
compared to 1999.
Expenses
In 2001 total operating expenses of $2.7 billion were down $50 million or 1.8
percent compared with 2000. This decline is mainly due to an $18 million net
decrease in fuel and purchased power costs and a $56 million decrease in
non-production operation and maintenance expenses, offset by a $19 million
increase in depreciation. Fuel expenses, including purchased power, are offset
by fuel revenues and have no effect on net income.
In 2000 total operating expenses of $2.7 billion were up $235 million or 9.4
percent compared with the prior year. This increase was mainly due to a $183
million increase in fuel and purchased power costs, accompanied by a $23 million
increase in maintenance expenses.
II-49
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net KWH generated were as follows:
--------------------------
2001 2000 1999
--------------------------
Total generation
(billions of KWHs) 68 65 63
Sources of generation
(percent) --
Coal 64 72 72
Nuclear 18 19 20
Hydro 6 3 5
Oil & Gas 12 6 3
Average cost of fuel per net
KWH generated
(cents) -- 1.56 1.54 1.44
==============================================================
In 2001, total fuel and purchased power costs of $1.3 billion decreased $18
million (1.4 percent), while total energy sales increased 1,174 million kilowatt
hours (1.6 percent) compared with the amounts recorded in 2000. Fuel and
purchased power costs in 2000 increased $183 million (16 percent) compared to
1999.
Purchased power consists of purchases from affiliates in the Southern
electric system and non-affiliated companies. Purchased power transactions among
the Company and its affiliates will vary from period to period depending on
demand, the availability, and the variable production cost of generating
resources at each company. During 2001 purchased power transactions from
non-affiliates decreased $20 million (12 percent) due to the addition in May
2001 of a combined cycle unit and an 82 percent increase in hydro generation
compared to the previous year. The hydro generation increase occurred from
greater stream flows in 2001 compared to the previous year.
The 6 percent decrease in other operation expense in 2001 as compared to
2000 is primarily due to a decrease in administrative and general expenses,
which can be mainly attributed to insurance refunds.
The 8.5 percent decrease in maintenance expense in 2001 as compared to 2000
is primarily due to a decrease in power production expense as a result of timing
of maintenance for steam power generation facilities. The 8.4 percent increase
in maintenance expense in 2000 as compared to 1999 is primarily attributable to
an increase in the maintenance of overhead distribution lines and additional
accruals to partially replenish the natural disaster reserve.
Depreciation and amortization expense increased 5.2 percent in 2001 and 4.9
percent in 2000. These increases reflect additions to property, plant, and
equipment.
Total net interest and other charges increased $10 million (4.0 percent)
in 2001. The increase reflected a decrease in Allowance for Funds Used During
Construction (AFUDC) resulting in a smaller credit to interest expense than was
recorded in 2000. Total net interest and other charges increased $19 million
(7.9 percent) in 2000 primarily from an increase in interest on long-term debt
offset by an increase in AFUDC, which resulted in a larger credit to interest
expense.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
General
The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of future
earnings depends on numerous factors. The major factor is the ability of the
Company to achieve energy sales growth while containing cost in a more
competitive environment. Growth in energy sales is subject to a number of
factors. These factors include weather, competition, new short- and long-term
II-50
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
contracts with neighboring utilities, energy conservation practiced by
customers, the elasticity of demand, and the rate of economic growth in the
Company's service area.
Assuming normal weather, sales to retail customers are projected to grow
approximately 2.4 percent annually on average during 2002 through 2006.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
state of Alabama. Prices for electricity provided by the Company to retail
customers are set by the Alabama Public Service Commission (APSC) under
cost-based regulatory principles.
Rates to retail customers served by the Company are regulated by the APSC.
Rates for the Company can be adjusted periodically within certain limitations
based on earned retail rate of return compared with an allowed return. The rates
also provide for adjustments to recognize the placing of new generating
facilities into retail service under Rate CNP (Certificated New Plant).
Effective July 2001, the Company's retail rates were adjusted by 0.6 percent
under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into
commercial operation on May 1, 2001. Most recently, a 2 percent increase in
retail rates was effective in October 2001, in accordance with the Rate
Stabilization Equalization plan. See Note 3 to the financial statements under
"Retail Rate Adjustment Procedures" for additional information.
In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items-- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues.
In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000 the APSC certified a seven-year
purchased power agreement pertaining to 615 megawatts of the wholesale
generating facilities, which were sold to Southern Power in June 2001 and are
under construction in Autaugaville, Alabama. All of the 615 megawatts will be
delivered beginning in 2003. In addition the APSC certified a seven-year
purchased power agreement with a third party for approximately 630 megawatts;
one half of the power will be delivered beginning in 2003 while the remaining
half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail
rates when the contracted capacity delivery begins.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash income of
approximately $57 million in 2001. Future pension income is dependent on several
factors including trust earnings and changes to the plan. For the Company,
pension income is a component of the regulated rates and does not have a
significant effect on net income. For more information see Note 2 to the
financial statements.
The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. The Clean Air Act and other important environmental items are
discussed later under "Environmental Matters."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve
as a result of regulatory and competitive factors. Among the primary agents of
change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act
allows independent power producers (IPPs) to access a utility's transmission
network in order to sell electricity to other utilities. This enhances the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and/or commercial customers and sell excess energy generation to other
utilities. Also, electricity sales for resale rates are affected by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the recent restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things
these initiatives allow customers to choose their electricity provider. Some
states have approved initiatives that result in a separation of the ownership
and/or operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While various restructuring and
II-51
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
competition initiatives have been discussed in Alabama, none have been enacted.
In October 2000 the APSC completed a two-year study of electric industry
restructuring, concluding that (i) restructuring of the electric utility
industry in Alabama was not in the public interest and (ii) the APSC itself
would not mandate retail competition or electric industry restructuring without
enabling state legislation. Electric utility restructuring would require
numerous issues to be resolved, including significant ones relating to recovery
of any stranded investments, full cost recovery of energy produced, and other
issues related to the energy crisis that occurred in California. As a result of
that crisis, many states have either discontinued or delayed implementation of
initiatives involving retail deregulation.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the Company does not remain a low-cost producer and provide
quality service, then energy sales growth could be limited, and this could
significantly erode earnings.
The Company had 1,230 megawatts of wholesale generating facilities under
construction in 2001 at Autaugaville, Alabama. In June 2001 the Company sold
this project to Southern Power Company, a new Southern Company subsidiary formed
in 2001 to construct, own, and manage wholesale generating assets in the
Southeast. The Company has entered into a purchased power agreement with
Southern Power, through May 2010, for half of the capacity of these generating
facilities.
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final ruling on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company and its operating companies, including the Company, have
submitted a series of status reports informing the FERC of progress toward the
development of a Southeastern RTO. In these status reports, Southern Company
explained that it is developing a for-profit RTO known as SeTrans with a number
of non-jurisdictional cooperative and public power entities. Recently, Entergy
Corporation and Cleco Power joined the SeTrans development process. In January
2002 the sponsors of SeTrans held a public meeting to form a Stakeholder
Advisory Committee, which will participate in the development of the RTO.
Southern Company continues to work with the other sponsors to develop the
SeTrans RTO. The creation of SeTrans is not expected to have a material impact
on the Company's financial statements. The outcome of this matter cannot now be
determined.
Accounting Standards
Critical Policy
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operation is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change - effective April 1,
2002 - in accounting for certain contracts related to fuel supplies that contain
quantity options. These contracts will be accounted for as derivatives and
marked to market. However, due to the existence of the Company's cost-based fuel
recovery clause, this change is not expected to have a material impact on net
income.
In June 2001 the FASB issued Statement No. 142, Goodwill and Other Intangible
Assets, which establishes new accounting and reporting standards for acquired
goodwill and other intangible assets and supersedes Accounting Principles Board
Opinion No. 17. Statement No. 142 addresses how intangible assets that are
II-52
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
acquired individually or with a group of other assets (but not those acquired in
a business combination) should be accounted for upon acquisition and on an
ongoing basis. Goodwill and intangible assets that have indefinite useful lives
will not be amortized but rather will be tested at least annually for
impairment. Intangible assets that have finite useful lives will continue to be
amortized over their useful lives, which are no longer limited to 40 years. The
Company adopted Statement No.142 in January 2002 with no material impact on the
financial statements.
Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.
FINANCIAL CONDITION
Overview
In 2001, despite significant cost control measures, the Company's earnings were
adversely impacted by an economic downturn and milder temperatures. However,
over the last several years the Company's financial condition has remained
stable as a result of growth in retail energy sales and cost control measures
combined with significant lowering of the cost of capital, achieved through the
refinancing and/or redemption of higher-cost long-term debt and preferred stock.
The Company had gross property additions of $636 million in 2001. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.
Exposure to Market Risk
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market. Realized gains and losses
are recognized in the income statement as incurred. At December 31, 2001,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Fair value of changes in energy
trading contracts and year-end valuations are as follows:
Changes
During the Year
------------------
Fair Value
- ---------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 567
Contracts realized or settled (509)
New contracts at inception -
Changes in valuation techniques -
Current period changes 156
- ---------------------------------------------------------------
Contracts end of year $ 214
===============================================================
Source of Year-End
Valuation Prices
------------------------------------
Maturity
Total ----------------------
Fair Value Year 1 1-3 Years
- ------------------------------------------------------------------
(in thousands)
- ------------------------------------------------------------------
Actively quoted $(4,840) $(4,801) $(39)
External sources 5,054 5,054 -
Models and other
methods - - -
- ------------------------------------------------------------------
Contracts end of Year $ 214 $ 253 $(39)
==================================================================
Also, based on the Company's overall variable rate long-term debt exposure
at December 31, 2001, a near-term 100 basis point change in interest rates would
not materially affect the financial statements.
For additional information, see Note 1 to the financial statements under
"Financial Instruments."
In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent of the
budgeted annual amount of natural gas purchases. The Company may not engage in
natural gas hedging activities that extend beyond a rolling 42-month window.
Capital Structure
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.8 percent in 2001, 42.2 percent in 2000, and 42.4
percent in 1999.
In August 2001, the Company issued $442 million of senior notes, the
proceeds of which were used to redeem the $131.5 million outstanding principal
of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other
corporate purposes, including the repayment of a portion of its short-term
indebtedness.
Capital Requirements
Capital expenditures are estimated to be $671 million for 2002, $592 million for
2003, and $673 million for 2004. See Note 4 to the financial statements for
additional details.
Actual construction costs may vary from estimates because of changes in such
factors as: business conditions; environmental regulations; nuclear plant
regulations; load projections; the cost and efficiency of construction labor,
equipment, and materials; and the cost of capital. In addition there can be no
assurance that costs related to capital expenditures will be fully recovered.
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $1.1 billion will be required by the end of 2004 for present
sinking fund requirements and maturities of long-term debt. The Company plans to
continue, when economically feasible, to retire higher cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
These capital requirements, lease obligations, and purchase commitments -
discussed in notes 4 and 8 to the financial statements - are as follows:
2002 2003 2004
- -----------------------------------------------------------------
(in millions)
Bonds -
First mortgage $ 4.5 $ - $ -
Pollution control - - -
Senior Notes - 573.2 525.0
Leases -
Capital 0.9 0.9 1.0
Operating 27.9 26.5 25.5
Purchase commitments -
Fuel 795.0 794.0 801.0
Purchased Power - 53.0 83.0
- -----------------------------------------------------------------
At the beginning of 2002, the Company had not used any of its available
credit arrangements. Credit arrangements are as follows:
Expires
----------------------------------
Total Unused 2002 2003 & Beyond
- -----------------------------------------------------------------
(in millions)
$964 $964 $574 $390
- -----------------------------------------------------------------
Environmental Matters
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company. Reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
were required in two phases. Phase I compliance began in 1995.
Southern Company achieved Phase I compliance at its affected plants by
primarily switching to low-sulfur coal and with some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $25 million for the Company.
Phase II sulfur dioxide compliance was required in 2000. The Company used
emission allowances and fuel switching to comply with Phase II requirements.
Also, equipment to control nitrogen oxide emissions was installed on additional
system fossil-fired units as necessary to meet Phase II limits. Compliance with
Phase II increased the Company's total construction expenditures through 2000 by
$63 million.
II-54
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
In December 2000, the Alabama Department of Environmental Management adopted
revisions to the State Implementation Plan for meeting the one-hour ozone
standard. New emission limits to comply with these requirements must be
implemented in May 2003. Two generating plants will be affected in the
Birmingham area. Capital expenditures for compliance with these new rules are
currently estimated at approximately $240 million, of which $170 million remains
to be spent.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
made the standards significantly more stringent. In the subsequent litigation of
these standards, the U. S. Supreme Court found the EPA's implementation program
for the new ozone standard unlawful and remanded it to the EPA. In addition, the
Federal District of Columbia Circuit Court of Appeals is considering other legal
challenges to these standards. A court decision is expected in the spring of
2002. If the standards are eventually upheld, implementation could be required
by 2007 to 2010.
In September 1998, the EPA issued nitrogen oxide reduction rules to the
states for implementation. The final rule affects 21 states, including Alabama.
Compliance is required by May 31, 2004 for most states including Alabama.
Capital expenditures for compliance with these new rules are currently estimated
at approximately $175 million.
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
On November 3, 1999, the EPA brought a civil action against the Company in
the U.S. District Court in Atlanta, Georgia. The complaint alleges violations of
the New Source Review provisions of the Clean Air Act with respect to coal-fired
generating facilities at the Company's Plants Miller, Barry, and Gorgas. The
civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The EPA concurrently issued to the Company a notice of violation
relating to these specific facilities, as well as Plants Greene County and
Gaston. In early 2000 the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation. The complaint and notice of
violation are similar to those brought against and issued to several other
electric utilities. The complaint and notice of violation allege that the
Company had failed to secure necessary permits or install additional pollution
control equipment when performing maintenance and construction at coal burning
plants constructed or under construction prior to 1978. In August 2000, the U.S.
District Court in Georgia granted the Company's motion to dismiss for lack of
jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims
against the Company in federal district court in Birmingham, Alabama. The case
has been stayed since the spring of 2001, pending a ruling by the U.S. Court of
Appeals for the Eleventh Circuit in the appeal of a very similar New Source
Review enforcement action against the Tennessee Valley Authority (TVA). The TVA
case involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on the Company, it is party to that case as well. The U.S. District Court
in Alabama has indicated that it will revisit the issue of a continued stay in
April 2002.
The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. However, an adverse outcome in this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. The Clean Air Act authorizes civil penalties
of up to $27,500 per day per violation at each generating unit. Prior to January
30, 1997, the penalty was $25,000 per day. This could affect future results of
operations, cash flows, and possibly financial condition unless such costs can
be recovered through regulated rates.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury, and perhaps other HAPS is warranted. The program is
being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and the regulations are scheduled to be finalized by the end
of 2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional
II-55
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup and
will recognize in the financial statements costs to clean up known sites. The
Company has not incurred any significant cleanup costs to date.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, and other environmental and health concerns could significantly affect
the Company. The impact of new legislation -- if any -- will depend on the
subsequent development and implementation of applicable regulations.
Sources of Capital
The Company plans to obtain the funds required for construction and other
purposes from sources similar to those used in the past, which were primarily
from internal sources. However, the type and timing of any financings - if
needed - will depend on market conditions and regulatory approval. In recent
years financings primarily have utilized unsecured debt and trust preferred
securities.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $10 million of commercial
paper.
As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the Company has established external trust funds for nuclear decommissioning
costs. In 1994 the Company also established an external trust fund for
postretirement benefits as ordered by the APSC. The cumulative effect of funding
these items over a long period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
Cautionary Statement Regarding Forward-Looking
Information
This Annual Report includes forward-looking statements in addition to historical
information. Forward-looking information includes, among other things,
statements concerning projected retail sales growth and scheduled completion of
new generation. In some cases forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
II-56
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report
"anticipates," "believes," "estimates," "predicts," "projects," "potential,"
"continue," or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action against the Company; the impact of fluctuations in commodity prices,
interest rates, and customer demand; state and federal rate regulations;
political, legal, and economic conditions and developments in the United States;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets
or businesses, which cannot be assured to be completed or beneficial to the
Company; the effects of and changes in economic conditions in the areas in which
the Company operates; the direct or indirect effects on the Company's business
resulting from the terrorist incidents on September 11, 2001, or any similar
such incidents or responses to such incidents; financial market conditions and
the results of financing efforts; the timing and acceptance of the Company's new
product and service offerings; the ability of the Company to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports (including
Form 10-K) filed from time to time by the Company with the Securities and
Exchange Commission.
II-57
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $2,747,673 $2,952,707 $2,811,117
Sales for resale --
Non-affiliates 485,974 461,730 415,377
Affiliates 245,189 166,219 92,439
Other revenues 107,554 86,805 66,541
- ---------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,586,390 3,667,461 3,385,474
- ---------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 1,000,828 963,275 855,632
Purchased power --
Non-affiliates 144,991 164,881 93,204
Affiliates 147,967 184,014 180,563
Other 508,264 538,529 531,696
Maintenance 275,510 301,046 277,724
Depreciation and amortization 383,473 364,618 347,574
Taxes other than income taxes 214,665 209,673 204,645
- ---------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,675,698 2,726,036 2,491,038
- ---------------------------------------------------------------------------------------------------------------------
Operating Income 910,692 941,425 894,436
Other Income (Expense):
Interest income, net 15,101 16,152 15,671
Equity in earnings of unconsolidated subsidiaries (Note 5) 4,494 3,156 2,650
Other, net (8,579) (2,226) (12,805)
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 921,708 958,507 899,952
- ---------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 246,436 235,331 217,066
Distributions on preferred securities of subsidiary (Note 8) 24,775 25,549 24,662
- ---------------------------------------------------------------------------------------------------------------------
Total interest and other, net 271,211 260,880 241,728
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 650,497 697,627 658,224
Income taxes (Note 7) 248,597 261,555 241,880
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 401,900 436,072 416,344
Accounting Change
Cumulative effect of accounting change
less income taxes of $215 thousand 353 - -
- ---------------------------------------------------------------------------------------------------------------------
Net Income 402,253 436,072 416,344
Dividends on Preferred Stock 15,524 16,156 16,464
- ---------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 386,729 $ 419,916 $ 399,880
=====================================================================================================================
The accompanying notes are an integral part of these statements.
II-58
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 402,253 $ 436,072 $ 416,344
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 437,490 412,998 403,332
Deferred income taxes and investment tax credits, net (21,569) 66,166 29,039
Other, net (122,651) (37,703) (12,661)
Changes in certain current assets and liabilities --
Receivables, net 88,325 (125,652) 33,509
Fossil fuel stock (38,663) 23,967 (1,344)
Materials and supplies (13,025) (10,662) (17,968)
Accounts payable (83,077) 107,702 (38,556)
Energy cost recovery, retail 154,320 (69,190) (97,869)
Other 34,503 23,336 5,930
- ----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 837,906 827,034 719,756
- ----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (635,540) (870,581) (809,044)
Sales of property 102,068 - -
Other (34,771) (49,414) (72,218)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (568,243) (919,995) (881,262)
- ----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (271,347) 184,519 96,824
Proceeds --
Common stock 15,642 - -
Other long-term debt 477,000 250,000 751,650
Preferred securities - - 50,000
Capital contributions from parent company 107,313 204,371 204,347
Redemptions --
First mortgage bonds (138,991) (111,009) (470,000)
Other long-term debt (19,021) (5,987) (104,836)
Preferred stock - - (50,000)
Payment of preferred stock dividends (14,942) (16,110) (15,788)
Payment of common stock dividends (393,900) (417,100) (399,600)
Other (9,908) (951) (15,864)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (248,154) 87,733 46,733
- ----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 21,509 (5,228) (114,773)
Cash and Cash Equivalents at Beginning of Period 14,247 19,475 134,248
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 35,756 $ 14,247 $ 19,475
============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $246,316 $237,066 $229,305
Income taxes (net of refunds) 223,961 175,303 170,121
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-59
BALANCE SHEETS
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 35,756 $ 14,247
Receivables --
Customer accounts receivable 281,985 337,870
Under-recovered retail fuel clause revenue 83,497 237,817
Other accounts and notes receivable 49,940 60,315
Affiliated companies 72,639 95,704
Accumulated provision for uncollectible accounts (5,237) (6,237)
Refundable income taxes - -
Fossil fuel stock, at average cost 99,278 60,615
Materials and supplies, at average cost 191,324 178,299
Other 74,640 52,624
- -------------------------------------------------------------------------------------------------------------------
Total current assets 883,822 1,031,254
- -------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 13,159,560 12,431,575
Less accumulated provision for depreciation 5,309,557 5,107,822
- -------------------------------------------------------------------------------------------------------------------
7,850,003 7,323,753
Nuclear fuel, at amortized cost 88,777 94,050
Construction work in progress 357,906 744,974
- -------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 8,296,686 8,162,777
- -------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 5) 44,742 38,623
Nuclear decommissioning trusts 317,508 313,895
Other 12,244 13,612
- -------------------------------------------------------------------------------------------------------------------
Total other property and investments 374,494 366,130
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 7) 334,830 345,550
Prepaid pension costs 314,100 255,256
Debt expense, being amortized 8,150 8,758
Premium on reacquired debt, being amortized 77,173 76,020
Department of Energy assessments 21,015 24,588
Other 108,031 95,772
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 863,299 805,944
- -------------------------------------------------------------------------------------------------------------------
Total Assets $10,418,301 $10,366,105
===================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-60
BALANCE SHEETS
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 8) $ 5,382 $ 844
Notes payable 9,996 281,343
Accounts payable --
Affiliated 98,268 124,534
Other 151,705 209,205
Customer deposits 42,124 36,814
Taxes accrued --
Income taxes 113,003 65,505
Other 19,023 19,471
Interest accrued 35,522 33,186
Vacation pay accrued 32,324 31,711
Other 93,589 97,743
- --------------------------------------------------------------------------------------------------------------------------
Total current liabilities 600,936 900,356
- --------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,742,346 3,425,527
- --------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 1,387,661 1,401,424
Deferred credits related to income taxes (Note 7) 202,881 222,485
Accumulated deferred investment tax credits 238,225 249,280
Employee benefits provisions 99,919 71,813
Prepaid capacity revenues (Note 6) 40,730 58,377
Other 130,214 176,559
- --------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,099,630 2,179,938
- --------------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) (Note 8) 347,000 347,000
- --------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 317,512 317,512
- --------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 3,310,877 3,195,772
- --------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $10,418,301 $10,366,105
==========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-61
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
2023 through 2024 7.30% - 7.75% $350,000 $488,991
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 350,000 488,991
- ----------------------------------------------------------------------------------------------------------------------------------
Senior notes --
Variable rate (2.28% at 1/1/02)
due March 3, 2003 167,000 -
5.35% due November 15, 2003 156,200 156,200
7.850% due May 15, 2003 250,000 250,000
7.125% due August 15, 2004 250,000 250,000
4.875% due September 1, 2004 275,000 -
5.49% due November 1, 2005 225,000 225,000
7.125% due October 1, 2007 200,000 200,000
5.375% due October 1, 2008 160,000 160,000
6.25% to 7.125% due 2010-2048 1,199,402 1,202,581
- ----------------------------------------------------------------------------------------------------------------------------------
Total senior notes 2,882,602 2,443,781
- ----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% due 2024 24,400 24,400
Variable rates (1.61% to 1.95% at 1/1/02)
due 2015-2017 89,800 89,800
Non-collateralized:
6.69% due 2021 50,000 65,000
Variable rates (1.75% to 2.05% at 1/1/02)
due 2021-2031 395,940 360,940
- ----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt (Note 8) 560,140 540,140
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 3,323 4,165
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (48,337) (50,706)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $217.2 million) 3,747,728 3,426,371
Less amount due within one year 5,382 844
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $3,742,346 $3,425,527 48.5% 46.9%
- ----------------------------------------------------------------------------------------------------------------------------------
II-62
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities: (Note 8)
$25 liquidation value --
7.375% $ 97,000 $ 97,000
7.60% 200,000 200,000
Auction rate (3.60% at 1/1/02) 50,000 50,000
- --------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $24.2 million) 347,000 347,000 4.5 4.8
- --------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par or stated value --
4.20% to 4.92% 47,512 47,512
$25 par or stated value --
5.20% to 5.83% 200,000 200,000
Auction rates -- at 1/1/02
3.10% to 3.557% 70,000 70,000
- --------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $15.2 million) 317,512 317,512 4.1 4.4
- --------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 6,000,000 shares
Outstanding - 6,000,000 shares in 2001
and 5,608,955 shares in 2000
Par value 240,000 224,358
Paid-in capital 1,850,676 1,743,363
Premium on Preferred Stock 99 99
Retained earnings 1,220,102 1,227,952
- --------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 3,310,877 3,195,772 42.9 43.9
- --------------------------------------------------------------------------------------------------------------------------
Total Capitalization $7,717,735 $7,285,811 100.0% 100.0%
==========================================================================================================================
The accompanying notes are an integral part of these statements.
II-63
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1999 $224,358 $1,334,645 $99 $1,224,965 $2,784,067
Net income after dividends on preferred stock - - - 399,880 399,880
Capital contributions from parent company - 204,347 - - 204,347
Cash dividends on common stock - - - (399,600) (399,600)
Other - - - 169 169
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 224,358 1,538,992 99 1,225,414 2,988,863
Net income after dividends on preferred stock - - - 419,916 419,916
Capital contributions from parent company - 204,371 - - 204,371
Cash dividends on common stock - - - (417,100) (417,100)
Other - - - (278) (278)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 224,358 1,743,363 99 1,227,952 3,195,772
Net income after dividends on preferred stock - - - 386,729 386,729
Capital contributions from parent company - 107,313 - - 107,313
Cash dividends on common stock - - - (393,900) (393,900)
Issuance of common stock 15,642 - - - 15,642
Other - - - (679) (679)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $240,000 $1,850,676 $99 $1,220,102 $3,310,877
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-64
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2001 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern LINC), Southern
Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern
Power), and other direct and indirect subsidiaries. The operating companies --
Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi
Power Company, and Savannah Electric and Power Company -- provide electric
service in four southeastern states. Contracts among the operating companies -
related to jointly-owned generating facilities, interconnecting transmission
lines, and the exchange of electric power -- are regulated by the Federal Energy
Regulatory Commission (FERC) and/or the Securities and Exchange Commission
(SEC). The system service company provides, at cost, specialized services to
Southern Company and its subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Power was
established in 2001 to construct, own, and manage Southern Company's competitive
generation assets and sell electricity at market-based rates in the wholesale
market.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The Company follows accounting principles generally accepted in the
United States and complies with the accounting policies and practices prescribed
by its respective regulatory commissions. The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States requires the use of estimates, and the actual results may differ
from those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Affiliate Transactions
The Company has an agreement with the system service company under which the
following services are rendered to the Company at cost: general and design
engineering, purchasing, accounting and statistical, finance and treasury, tax,
information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures, and other services with
respect to business and operations and power pool transactions. Costs for these
services amounted to $183 million, $187 million, and $218 million during 2001,
2000, and 1999, respectively.
The Company also has an agreement with Southern Nuclear to operate Plant
Farley and provide the following nuclear-related services at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting,
statistical, and employee relations; and other services with respect to business
and operations. Costs for these services amounted to $160 million, $148 million,
and $135 million during 2001, 2000, and 1999, respectively.
In 2001, the Company had under construction a 1,230 megawatt combined cycle
facility in Autaugaville, Alabama. In June 2001, the Company sold this project
to Southern Power Company, a new Southern Company affiliate formed in 2001 to
construct, own, and manage wholesale generating assets in the Southeast.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues associated with
certain costs that are expected to be recovered from customers through the
ratemaking process. Regulatory liabilities represent probable future reductions
in revenues associated with amounts that are expected to be credited to
customers through the ratemaking process.
II-65
NOTES (continued)
Alabama Power Company 2001 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:
2001 2000
-----------------------
(in millions)
Deferred income tax charges $ 335 $ 346
Deferred income tax credits (203) (222)
Premium on reacquired debt 77 76
Department of Energy assessments 21 25
Vacation pay 32 32
Natural disaster reserve (12) (18)
Other, net 57 30
- ----------------------------------------------------------------
Total $ 307 $ 269
================================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of FASB Statement No. 71, the Company would be required to
write off related regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair values.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Alabama and to wholesale customers in the southeast.
Revenues are recognized as services are rendered. Unbilled revenues are accrued
at the end of each fiscal period. Fuel revenues have no effect on net income
because they represent the recording of revenues to offset fuel expenses,
including the fuel component of purchased energy. Fuel rates billed to customers
are designed to fully recover fluctuating fuel costs over a period of time.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts continue to average less than 1 percent of revenues.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge based on nuclear generation for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $58
million in 2001, $61 million in 2000, and $63 million in 1999.
The Company has a contract with the U.S. Department of Energy (DOE) that
provides for the permanent disposal of spent nuclear fuel. The DOE failed to
begin disposing of spent fuel in January 1998 as required by the contract, and
the Company is pursuing legal remedies against the government for breach of
contract. Sufficient fuel storage capacity is available at Plant Farley to
maintain full-core discharge capability until the refueling outage scheduled in
2006 for Farley Unit 1 and the refueling outage scheduled in 2008 for Farley
Unit 2. Procurement of on-site dry spent fuel storage capacity at Plant Farley
is in progress, with the intent to place the capacity in operation as early as
2005.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is funded in part by
a special assessment on utilities with nuclear plants. This assessment is being
paid over a 15-year period, which began in 1993. This fund will be used by the
DOE for the decontamination and decommissioning of its nuclear fuel enrichment
facilities. The law provides that utilities will recover these payments in the
same manner as any other fuel expense. The Company estimates its remaining
liability under this law to be approximately $21 million at December 31, 2001.
This obligation is recognized in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.2 percent in 2001, 2000, and 1999. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to accumulated
provision for depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
Depreciation expense includes an amount for the expected cost of decommissioning
nuclear facilities and removal of other facilities.
The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial nuclear power reactors to establish a plan for providing with
reasonable assurance funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Amounts previously
recorded in internal reserves are being transferred into the external trust
funds over periods approved by the APSC. The NRC's minimum external funding
requirements are based on a generic estimate of the cost to decommission the
radioactive portions of a nuclear unit based on the size and type of reactor.
II-66
NOTES (continued)
Alabama Power Company 2001 Annual Report
The Company has filed plans with the NRC to ensure that -- over time -- the
deposits and earnings of the external trust funds will provide the minimum
funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the site
study year, and ultimate cost is the estimate to decommission the facility as of
retirement date. The estimated costs of decommissioning -- both site study costs
and ultimate costs - based on the most current study for Plant Farley were as
follows:
Site study basis (year) 1998
Decommissioning periods:
Beginning year 2017
Completion year 2031
------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $629
Non-radiated structures 60
------------------------------------------------------------
Total $689
============================================================
(in millions)
Ultimate costs:
Radiated structures $1,868
Non-radiated structures 178
------------------------------------------------------------
Total $2,046
============================================================
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the APSC. The amount expensed in 2001 and fund balances as of
December 31, 2001 were:
(in millions)
Amount expensed in 2001 $ 18
-------------------------------------------------------------
Accumulated provisions:
External trust funds, at fair value $318
Internal reserves 36
-------------------------------------------------------------
Total $354
=============================================================
All of the Company's decommissioning costs are approved for recovery by the
APSC through the ratemaking process. Significant assumptions include an
estimated inflation rate of 4.5 percent and an estimated trust earnings rate of
7.0 percent. The Company expects the APSC to periodically review and adjust, if
necessary, the amounts collected in rates for the anticipated cost of
decommissioning.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.
Allowance For Funds Used During Construction
(AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The amount of AFUDC capitalized was $19 million in 2001,
$43 million in 2000, and $23 million in 1999. The composite rate used to
determine the amount of allowance was 7.7 percent in 2001, 9.6 percent in 2000,
and 8.8 percent in 1999. AFUDC, net of income tax, as a percent of net income
after dividends on preferred stock was 3.3 percent in 2001, 8.4 percent in 2000,
and 4.7 percent in 1999.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction. The cost of
maintenance, repairs and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property--exclusive of minor
items of property--is capitalized.
Financial Instruments
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on
net income was immaterial.
The Company uses derivative financial instruments to hedge exposures to
fluctuations in foreign currency exchange rates and certain commodity prices.
II-67
NOTES (continued)
Alabama Power Company 2001 Annual Report
Gains and losses on qualifying hedges are deferred and recognized either in
income or as an adjustment to the carrying amount of the hedged item when the
transaction occurs.
The Company and its affiliates, through the system service company acting as
their agent, enters into commodity related forward and option contracts to limit
exposure to changing prices on certain fuel purchases and electricity purchases
and sales. Substantially all of the Company's bulk energy purchases and sales
contracts meet the definition of a derivative under FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities. In many cases
these fuel and electricity contracts qualify for normal purchase and sale
exceptions under Statement No. 133 and are accounted for under the accrual
method. Other contracts qualify as cash flow hedges of anticipated transactions,
resulting in the deferral of related gains and losses and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.
In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent of the
budgeted annual amount of natural gas purchases. The Company may not engage in
natural gas hedging activities that extend beyond a rolling 42-month window.
The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.
Other Company financial instruments for which the carrying amount did not
equal fair value at December 31 are as follows:
Carrying Fair
Amount Value
-------------------------
(in millions)
Long-term debt:
At December 31, 2001 $3,744 $3,800
At December 31, 2000 3,422 3,375
Preferred Securities:
At December 31, 2001 347 346
At December 31, 2000 347 344
--------------------------------------------------------------
The fair value for long-term debt and preferred securities was based on
either closing market prices or closing prices of comparable instruments.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Natural Disaster Reserve
In accordance with an APSC order, the Company has established a Natural Disaster
Reserve. The Company is allowed to accrue $250 thousand per month until the
maximum accumulated provision of $32 million is attained. Higher accruals to
restore the reserve to its authorized level are allowed whenever the balance in
the reserve declines below $22.4 million. At December 31, 2001, the reserve
balance was $12 million.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all employees may become
eligible for such benefits when they retire. The Company funds trusts to the
extent deductible under federal income tax regulations or to the extent required
by the APSC and the FERC. In late 2000 the Company adopted several pension and
postretirement benefit plan changes that had the effect of increasing benefits
to both current and future retirees.
II-68
NOTES (continued)
Alabama Power Company 2001 Annual Report
The measurement date for plan assets and obligations is September 30 of each
year. The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
2001 2000
- -------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Long-term return on plan assets 8.50 8.50
- -------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
------------------------
2001 2000
- ------------------------------------------------------------
(in millions)
Balance at beginning of year $925 $896
Service cost 25 23
Interest cost 70 65
Benefits paid (56) (51)
Actuarial gain and
employee transfers (1) (8)
Amendments 48 -
- ------------------------------------------------------------
Balance at end of year $1,011 $925
============================================================
Plan Assets
------------------------
2001 2000
- ------------------------------------------------------------
(in millions)
Balance at beginning of year $1,921 $1,647
Actual return on plan assets (277) 302
Benefits paid (56) (51)
Employee transfers (4) 23
- ------------------------------------------------------------
Balance at end of year $1,584 $1,921
============================================================
The accrued pension costs recognized in the Balance Sheets were as
follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $ 573 $ 996
Unrecognized transition obligation (15) (20)
Unrecognized prior service cost 78 36
Unrecognized net actuarial gain (322) (757)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 314 $ 255
===============================================================
Components of the pension plan's net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 25 $ 23 $ 23
Interest cost 70 65 58
Expected return on plan assets (131) (119) (109)
Recognized net actuarial gain (22) (19) (13)
Net amortization 1 (1) (1)
- ---------------------------------------------------------------
Net pension income $ (57) $ (51) $ (42)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
-------------------------
2001 2000
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $264 $264
Service cost 5 4
Interest cost 24 19
Benefits paid (18) (12)
Actuarial gain and
employee transfers (13) (11)
Amendments 86 -
- -------------------------------------------------------------
Balance at end of year $348 $264
=============================================================
Plan Assets
-------------------------
2001 2000
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $192 $161
Actual return on plan assets (24) 25
Employer contributions 19 18
Benefits paid (18) (12)
- -------------------------------------------------------------
Balance at end of year $169 $192
=============================================================
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $ (179) $ (72)
Unrecognized transition obligation 45 49
Prior service cost 82 -
Unrecognized net actuarial gain (9) (35)
Fourth quarter contributions 8 4
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (53) $ (54)
===============================================================
II-69
NOTES (continued)
Alabama Power Company 2001 Annual Report
Components of the plans' net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 5 $ 4 $ 5
Interest cost 24 19 18
Expected return on plan assets (15) (13) (11)
Net amortization 7 4 4
- ---------------------------------------------------------------
Net postretirement cost $ 21 $ 14 $ 16
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $30 $26
Service and interest costs 3 2
===============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $12
million, $11 million, and $10 million, respectively.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs totaling $13.0
million, $2.6 million and $5.6 million for the years 2001, 2000 and 1999,
respectively. These costs were deferred and are being amortized in accordance
with regulatory treatment. The unamortized balance of these costs was $11.9
million at December 31, 2001.
3. CONTINGENCIES AND REGULATORY
MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in U.S. District Court in Georgia against the Company. The complaint
alleges violations of the New Source Review provisions of the Clean Air Act with
respect to coal-fired generating facilities at the Company's Plants Miller,
Barry, and Gorgas. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The Clean Air Act authorizes civil penalties
of up to $27,500 per day, per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day.
The EPA concurrently issued to the Company a notice of violation relating to
these specific facilities, as well as Plants Greene County and Gaston. In early
2000, the EPA filed a motion to amend its complaint to add the violations
alleged in its notice of violation. The complaint and the notice of violation
are similar to those brought against and issued to several other electric
utilities. The complaint and the notice of violation allege that the Company
failed to secure necessary permits or install additional pollution control
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. On August 1, 2000, the U.S.
District Court granted the Company's motion to dismiss for lack of jurisdiction
in Georgia. On January 12, 2001, the EPA re-filed its claims against the Company
in federal district court in Birmingham, Alabama.
The Company's case has been stayed since the spring of 2001, pending a ruling
by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very
similar New Source Review enforcement action against the Tennessee Valley
Authority (TVA). The TVA case involves many of the same legal issues raised by
the actions against the Company. Because the outcome of the TVA case could have
II-70
NOTES (continued)
Alabama Power Company 2001 Annual Report
a significant adverse impact on the Company, it is a party to that case as well.
The U.S. District Court in Alabama has indicated that it will revisit the issue
of a continued stay in April 2002.
The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
Retail Rate Adjustment Procedures
The APSC has adopted rates that provide for periodic adjustments based upon the
Company's earned return on end-of-period retail common equity. The rates also
provide for adjustments to recognize the placing of new generating facilities
into retail service under Rate CNP (Certificated New Plant). Both increases and
decreases have been placed into effect since the adoption of these rates.
Effective July 2001, the Company's retail rates were adjusted by 0.6 percent
under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into
commercial operation on May 1, 2001. Most recently, a 2 percent increase in
retail rates was effective in October 2001 in accordance with the Rate
Stabilization Equalization plan. The rate adjustment procedures allow a return
on common equity range of 13.0 percent to 14.5 percent and limit increases or
decreases in rates to 4 percent in any calendar year.
In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. During the
years 2001, 2000, and 1999, the Company did not record any such reductions.
In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000, the APSC certified a seven-year
purchased power agreement pertaining to 615 megawatts of the wholesale
generating facilities which were sold to Southern Power in June 2001 and are
under construction in Autaugaville, Alabama. All of the 615 megawatts will be
delivered beginning in 2003. In addition the APSC certified a seven-year
purchased power agreement with a third party for approximately 630 megawatts;
one half of the power will be delivered beginning in 2003 while the remaining
half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail
rates when the contracted capacity delivery begins.
In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent of the
budgeted annual amount of natural gas purchases. The Company may not engage in
natural gas hedging activities that extend beyond a rolling 42-month window.
The Company's ratemaking procedures will remain in effect until the APSC
votes to modify or discontinue them.
4. COMMITMENTS
Construction Program
During 2001, the Company completed the replacement of the steam generators
at Plant Farley, as well as the construction of new generating capacity at Plant
Barry. Significant construction will continue related to transmission and
distribution facilities and the upgrading of generating plants, including the
expenditures necessary to comply with environmental regulation.
The Company currently estimates property additions to be $671 million in
2002, $592 million in 2003, and $673 million in 2004.
In connection with the transfer of the Autaugaville construction project,
the Company has assigned $71 million in vendor equipment contracts to Southern
Power. While the Company could be obligated to assume responsibility for these
contracts if Southern Power fails to meet these commitments, Southern Company
has entered into limited keep-well arrangements whereby Southern Company would
contribute funds to Southern Power either through loans or capital contributions
in order to fund performance by Southern Power as equipment purchaser under
certain contingencies. Southern Company has also guaranteed Southern Power
obligations totaling $6.6 million for the Company's construction of transmission
interconnection facilities to the plant.
The capital budget is subject to periodic review and revision, and actual
capital costs incurred may vary from estimates because of changes in such
II-71
NOTES (continued)
Alabama Power Company 2001 Annual Report
factors as: business conditions; environmental regulations; nuclear plant
regulations; load projections; the cost and efficiency of construction labor,
equipment, and materials; and the cost of capital. In addition there can be no
assurance that costs related to capital expenditures will be fully recovered.
Purchased Power Commitments
The Company has entered into various long-term commitments for the purchase of
electricity. Estimated total long-term obligations at December 31, 2001 were as
follows:
Commitments
-----------------------------------
Non-
Year Affiliated Affiliated Total
- ---- ----------------------------------
(in millions)
2002 $ - $ - $ -
2003 37 16 53
2004 49 34 83
2005 49 37 86
2006 49 38 87
2007 and thereafter 160 142 302
- --------------------------------------------------------------
Total commitments $344 $267 $611
==============================================================
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases these contracts contain provisions for
price escalations, minimum purchase levels, and other financial commitments.
Total estimated long-term obligations at December 31, 2001, were as follows:
Year Commitments
- ---- ---------------
(in millions)
2002 $ 795
2003 794
2004 801
2005 571
2006 512
2007 and thereafter 1,020
- ---------------------------------------------------------------
Total commitments $4,493
===============================================================
In addition, the system service company acts as agent for the five operating
companies and Southern Power with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various indices at the actual time of
delivery; therefore, only the volume commitments are firm. The Company's
committed volumes allocated based on usage projections, as of December 31, 2001,
are as follows:
Year Natural Gas
- ---- -----------
(MMBtu)
2002 77,365,361
2003 72,139,927
2004 45,600,417
2005 22,849,132
2006 14,808,334
2007 and thereafter 5,609,190
- ------------------------------------------------------------
Total commitments 238,372,361
============================================================
Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.
Operating Leases
The Company has entered into rental agreements for coal rail cars, vehicles, and
other equipment with various terms and expiration dates. These expenses totaled
$27.9 million in 2001, $20.9 million in 2000, and $17.8 million in 1999. At
December 31, 2001, estimated minimum rental commitments for noncancellable
operating leases were as follows:
Year Commitments
- ---- ----------------
(in millions)
2002 $ 27.9
2003 26.5
2004 25.5
2005 21.6
2006 14.4
2007 and thereafter 38.1
- --------------------------------------------------------------
Total minimum payments $ 154.0
==============================================================
In addition to the rental commitments above, the Company has potential
obligations upon expiration of certain leases with respect to the residual value
of the leased property. These leases expire in 2004 and 2006, and the Company's
maximum obligations are $25.7 million and $66.0 million, respectively. At the
termination of the leases, at the Company's option, the Company may negotiate
an extension, exercise its purchase option, or the property can be sold to a
third party. The Company expects that the fair market value of the leased
property would substantially reduce or eliminate the Company's payments under
the residual value obligation.
5. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power own equally all of the outstanding capital stock
of Southern Electric Generating Company (SEGCO), which owns electric generating
units with a total rated capacity of 1,020 megawatts, together with associated
II-72
NOTES (continued)
Alabama Power Company 2001 Annual Report
transmission facilities. The capacity of these units is sold equally to the
Company and Georgia Power under a contract which, in substance, requires
payments sufficient to provide for the operating expenses, taxes, interest
expense and a return on equity, whether or not SEGCO has any capacity and energy
available. The term of the contract extends automatically for two-year periods,
subject to either party's right to cancel upon two year's notice. The Company's
share of expenses totaled $80 million in 2001, $85 million in 2000, and $92
million in 1999 and is included in "Purchased power from affiliates" in the
Statements of Income.
In addition the Company has guaranteed unconditionally the obligation of
SEGCO under an installment sale agreement for the purchase of certain pollution
control facilities at SEGCO's generating units, pursuant to which $24.5 million
principal amount of pollution control revenue bonds are outstanding. Georgia
Power has agreed to reimburse the Company for the pro rata portion of such
obligation corresponding to its then proportionate ownership of stock of SEGCO
if the Company is called upon to make such payment under its guaranty.
At December 31, 2001, the capitalization of SEGCO consisted of $58 million
of equity and $86 million of long-term debt on which the annual interest
requirement is $2.2 million. SEGCO paid dividends totaling $0.7 million in 2001,
$5.1 million in 2000, and $4.3 million in 1999 of which one-half of each was
paid to the Company. SEGCO's net income was $7.5 million, $5.9 million, and $5.4
million for 2001, 2000, and 1999, respectively.
The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 2001, is as follows:
Total
Megawatt Company
Facility (Type) Capacity Ownership
--------------------- ------------ -------------
Greene County 500 60.00% (1)
(coal)
Plant Miller
Units 1 and 2 1,320 91.84% (2)
(coal)
-----------------------------------------------------------
(1) Jointly owned with an affiliate, Mississippi Power Company.
(2) Jointly owned with Alabama Electric Cooperative, Inc.
Company Accumulated
Facility Investment Depreciation
--------------------- -------------- ---------------
(in millions)
Greene County $101 $ 49
Plant Miller
Units 1 and 2 747 326
----------------------------------------------------------
6. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the other operating companies of Southern Company have entered
into long-term contractual agreements for the sale and lease of capacity and
energy to certain non-affiliated utilities located outside the system's service
area. These agreements -- expiring at various dates discussed below -- are firm
and related to specific generating units. Because the energy is generally
provided at cost under these agreements, profitability is primarily affected by
capacity revenues.
Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority
(JEA). Under these agreements approximately 1,237 megawatts of capacity are
scheduled to be sold through 2010. The Company's capacity revenues amounted to
$125 million in 2001, $127 million in 2000, and $122 million in 1999.
Alabama Municipal Electric Authority (AMEA)
Capacity Contracts
In 1986 the Company entered into a firm power sales contract with AMEA entitling
AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for a period
of 15 years (1986 Contract). In October 1991 the Company entered into a second
firm power sales contract with AMEA entitling AMEA to scheduled amounts of
additional capacity (to a maximum 80 megawatts) for a period of 15 years (1991
Contract). Under the terms of the contracts, the Company received payments from
AMEA representing the net present value of the revenues associated with the
respective capacity entitlements, discounted at effective annual rates of 9.96
percent and 11.19 percent for the 1986 and 1991 contracts, respectively. The
1986 contract expired in July 2001, however, the payments for the 1991 contract
will continue to be recognized as operating revenues and the discounts will be
amortized to other interest expense as scheduled capacity is made available over
the terms of the contract.
To secure AMEA's advance payments and the Company's performance obligation
under the contracts, the Company issued and delivered to an escrow agent first
mortgage bonds representing the maximum amount of liquidated damages payable by
the Company in the event of a default under the contracts. No principal or
interest is payable on such bonds unless and until a default by the Company
II-73
NOTES (continued)
Alabama Power Company 2001 Annual Report
occurs. As the liquidated damages decline, a portion of the bond equal to the
decrease is returned to the Company. At December 31, 2001, $38.1 million of the
1991 bond was held by the escrow agent under the contract.
7. INCOME TAXES
At December 31, 2001, the tax-related regulatory assets and liabilities were
$335 million and $203 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized interest. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of the income tax provisions are as follows:
2001 2000 1999
--------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $234 $168 $194
Deferred (20) 60 24
- -----------------------------------------------------------------
214 228 218
- -----------------------------------------------------------------
State --
Current 37 27 19
Deferred (2) 7 5
- -----------------------------------------------------------------
35 34 24
- -----------------------------------------------------------------
Total $249 $262 $242
=================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
2001 2000
------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 1,034 $ 992
Property basis differences 390 405
Fuel cost adjustment 28 93
Premium on reacquired debt 29 30
Pensions 89 75
Other 23 12
- -----------------------------------------------------------------
Total 1,593 1,607
- -----------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 13 18
Other deferred costs 14 14
Postretirement benefits 21 24
Unbilled revenue 18 23
Other 93 81
- -----------------------------------------------------------------
Total 159 160
- -----------------------------------------------------------------
Total deferred tax liabilities, net 1,434 1,447
Portion included in current liabilities, net (47) (46)
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,387 $1,401
=================================================================
Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $11 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
2001 2000 1999
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.5 3.1 2.4
Non-deductible book
depreciation 1.5 1.4 1.6
Differences in prior years'
deferred and current tax rates (1.3) (1.3) (1.3)
Other (0.5) (0.7) (0.9)
- ---------------------------------------------------------------
Effective income tax rate 38.2% 37.5% 36.8%
===============================================================
Southern Company files a consolidated federal and certain state income tax
returns. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.
II-74
NOTES (continued)
Alabama Power Company 2001 Annual Report
8. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:
Date of Maturity
Issue Amount Rate Notes Date
---------------------------------------------------
(millions) (millions)
Trust I 1/1996 $ 97 7.375% $100 3/2026
Trust II 1/1997 200 7.60 206 12/2036
Trust III 2/1999 50 Auction 52 2/2029
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above. The distribution rate of Trust III's auction rate securities was 3.60% at
January 1, 2002.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.
The Trusts are subsidiaries of the Company and accordingly are consolidated
in the Company's financial statements.
Pollution Control Bonds
Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. The Company is required to make payments sufficient for the
authorities to meet principal and interest requirements of such bonds. With
respect to $114.2 million of such pollution control obligations, the Company has
authenticated and delivered to the trustees a like principal amount of first
mortgage bonds as security for its obligations under the installment purchase
agreements. No principal or interest on these first mortgage bonds is payable
unless and until a default occurs on the installment purchase agreements.
In 2001, the Company sold, through a public authority, $20 million of
pollution control bonds, the proceeds of which were used to pay certain costs
incurred in connection with the acquisition, construction, installation, and
equipping of certain local district heating facilities and sewage and solid
waste facilities at two of the Company's generation facilities.
Senior Notes
In August 2001 the Company issued $442 million of unsecured senior notes, the
proceeds of which were used to redeem the $131.5 million outstanding principal
of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other
corporate purposes including the repayment of a portion of its short-term
indebtedness. All of the Company's senior notes are, in effect, subordinate to
all secured debt of the Company, including its first mortgage bonds.
Capitalized Leases
The estimated aggregate annual maturities of capitalized lease obligations
through 2006 are as follows: $0.9 million in 2002, $0.9 million in 2003, $1.0
million in 2004, $0.4 million in 2005, and $0.1 million in 2006.
Securities Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
2001 2000
----------------------
(in thousands)
First mortgage bond maturities
and redemptions $4,498 $ -
Other long-term debt maturities 884 844
------------------------------------------------------------
Total long-term debt due within
one year $5,382 $844
============================================================
The annual first mortgage bond improvement fund requirement is 1 percent of
the aggregate principal amount of bonds of each series authenticated, so long as
a portion of that series is outstanding, and may be satisfied by the deposit of
cash and/or reacquired bonds, the certification of unfunded property additions,
or a combination thereof.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $964 million
(including $454 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$574 million expire at various times during 2002 and $390 million expire in
II-75
NOTES (continued)
Alabama Power Company 2001 Annual Report
2004. In certain cases, such lines require payment of a commitment fee based on
the unused portion of the commitment or the maintenance of compensating balances
with the banks. Because the arrangements are based on an average balance, the
Company does not consider any of its cash balances to be restricted as of any
specific date. Moreover, the Company borrows from time to time pursuant to
arrangements with banks for uncommitted lines of credit. The amount of
commercial paper outstanding at December 31, 2001 was $10 million.
At December 31, 2001, the Company had regulatory approval to have
outstanding up to $1 billion of short-term borrowings.
Assets Subject to Lien
The Company's mortgage, as amended and supplemented, securing the first mortgage
bonds issued by the Company, constitutes a direct lien on substantially all of
the Company's fixed property and franchises.
Dividend Restrictions
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 2001, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (the Act), the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at Plant
Farley. The Act provides funds up to $9.5 billion for public liability claims
that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $200 million by American Nuclear Insurers (ANI),
with the remaining coverage provided by a mandatory program of deferred premiums
which could be assessed, after a nuclear incident, against all owners of nuclear
reactors. The Company could be assessed up to $88 million per incident for each
licensed reactor it operates but not more than an aggregate of $10 million per
incident to be paid in a calendar year for each reactor. Such maximum
assessment, excluding any applicable state premium taxes, for the Company is
$176 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional cost that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years.
Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $35 million.
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. However, both companies revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies shall be
dedicated first for the sole purpose of placing the reactor in a safe and stable
condition after an accident. Any remaining proceeds are to be applied next
toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the Company or
to its bond trustees as may be appropriate under the policies and applicable
trust indentures.
All retrospective assessments, whether generated for liability, property or
replacement power may be subject to applicable state premium taxes.
II-76
NOTES (continued)
Alabama Power Company 2001 Annual Report
10. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 2001 and 2000 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- -------------------- -----------------------------------------
(in millions)
March 2001 $ 850 $180 $ 70
June 2001 904 194 75
September 2001 1,061 362 180
December 2001 772 175 62
March 2000 $ 746 $172 $ 68
June 2000 900 229 103
September 2000 1,137 390 209
December 2000 884 151 40
- -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-77
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Alabama Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111
Net Income after Dividends
on Preferred Stock (in thousands) $386,729 $419,916 $399,880 $377,223 $375,939
Cash Dividends
on Common Stock (in thousands) $393,900 $417,100 $399,600 $367,100 $339,600
Return on Average Common Equity (percent) 11.89 13.58 13.85 13.63 13.76
Total Assets (in thousands) $10,418,301 $10,366,105 $9,648,704 $9,225,698 $8,812,867
Gross Property Additions (in thousands) $635,540 $870,581 $809,044 $610,132 $451,167
- ----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,310,877 $3,195,772 $2,988,863 $2,784,067 $2,750,569
Preferred stock 317,512 317,512 317,512 317,512 255,512
Company obligated mandatorily
redeemable preferred securities 347,000 347,000 347,000 297,000 297,000
Long-term debt 3,742,346 3,425,527 3,190,378 2,646,566 2,473,202
- ----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,717,735 $7,285,811 $6,843,753 $6,045,145 $5,776,283
============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 42.9 43.9 43.7 46.1 47.6
Preferred stock 4.1 4.4 4.6 5.3 4.4
Company obligated mandatorily
redeemable preferred securities 4.5 4.8 5.1 4.9 5.2
Long-term debt 48.5 46.9 46.6 43.7 42.8
- ----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
============================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's A A A+ A+ A+
Fitch A+ AA- AA- AA- AA-
Preferred Stock -
Moody's Baa1 a2 a2 a2 a2
Standard and Poor's BBB+ BBB+ A- A A
Fitch A- A A A A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 A2
Standard and Poor's A A A A A
Fitch A A+ A+ A+ A+
============================================================================================================================
Customers (year-end):
Residential 1,139,542 1,132,410 1,120,574 1,106,217 1,092,161
Commercial 196,617 193,106 188,368 182,738 177,362
Industrial 4,728 4,819 4,897 5,020 5,076
Other 751 745 735 733 728
- ----------------------------------------------------------------------------------------------------------------------------
Total 1,341,638 1,331,080 1,314,574 1,294,708 1,275,327
============================================================================================================================
Employees (year-end): 6,706 6,871 6,792 6,631 6,531
- ----------------------------------------------------------------------------------------------------------------------------
II-78
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Alabama Power Company 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,138,499 $1,222,509 $ 1,145,646 $ 1,133,435 $ 997,507
Commercial 829,760 854,695 807,098 779,169 724,148
Industrial 763,934 859,668 843,090 853,550 775,591
Other 15,480 15,835 15,283 14,523 13,563
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 2,747,673 2,952,707 2,811,117 2,780,677 2,510,809
Sales for resale - non-affiliates 485,974 461,730 415,377 448,973 431,023
Sales for resale - affiliates 245,189 166,219 92,439 103,562 161,795
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,478,836 3,580,656 3,318,933 3,333,212 3,103,627
Other revenues 107,554 86,805 66,541 53,161 45,484
- ------------------------------------------------------------------------------------------------------------------------------
Total $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 15,880,971 16,771,821 15,699,081 15,794,543 14,336,408
Commercial 12,798,711 12,988,728 12,314,085 11,904,509 11,330,312
Industrial 20,460,022 22,101,407 21,942,889 21,585,117 20,727,912
Other 198,102 205,827 201,149 196,647 180,389
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 49,337,806 52,067,783 50,157,204 49,480,816 46,575,021
Sales for resale - non-affiliates 15,277,839 14,847,533 12,437,599 11,840,910 12,329,480
Sales for resale - affiliates 8,843,094 5,369,474 5,031,781 5,976,099 8,993,326
- ------------------------------------------------------------------------------------------------------------------------------
Total 73,458,739 72,284,790 67,626,584 67,297,825 67,897,827
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.17 7.29 7.30 7.18 6.96
Commercial 6.48 6.58 6.55 6.55 6.39
Industrial 3.73 3.89 3.84 3.95 3.74
Total retail 5.57 5.67 5.60 5.62 5.39
Sales for resale 3.03 3.11 2.91 3.10 2.78
Total sales 4.74 4.95 4.91 4.95 4.57
Residential Average Annual
Kilowatt-Hour Use Per Customer 13,981 14,875 14,097 14,370 13,254
Residential Average Annual
Revenue Per Customer $1,002.30 $1,084.26 $1,028.76 $1,031.21 $922.21
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 12,153 12,122 11,379 11,151 11,151
Maximum Peak-Hour Demand (megawatts):
Winter 9,300 9,478 8,863 7,757 8,478
Summer 10,241 11,019 10,739 10,329 9,778
Annual Load Factor (percent) 62.5 59.3 59.7 62.9 62.7
Plant Availability (percent):
Fossil-steam 87.1 89.4 80.4 85.6 86.3
Nuclear 83.7 88.3 91.0 80.2 88.8
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 56.8 63.0 64.1 65.3 65.7
Nuclear 15.8 16.9 17.8 16.3 17.9
Hydro 5.1 2.9 4.7 6.9 7.5
Oil and gas 10.7 4.9 1.1 1.5 0.7
Purchased power -
From non-affiliates 4.4 4.6 4.5 3.3 2.4
From affiliates 7.2 7.7 7.8 6.7 5.8
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
II-79
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-80
MANAGEMENT'S REPORT
Georgia Power Company 2001 Annual Report
The management of Georgia Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with accounting principles generally
accepted in the United States and necessarily include amounts that are based on
the best estimates and judgments of management. Financial information throughout
this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls based upon the recognition that the cost of the
system should not exceed its benefits. The Company believes that 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, which is composed of three
independent directors, provides a broad overview of management's financial
reporting and control functions. At least three times a year 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 control and financial reporting matters. The internal
auditors and the 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 with 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 Georgia Power Company in conformity with accounting principles generally
accepted in the United States.
/s/David M. Ratcliffe
David M. Ratcliffe
President and Chief Executive Officer
/s/Thomas A. Fanning
Executive Vice President, Treasurer
and Chief Financial Officer
February 13, 2002
II-81
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 2001 and 2000, and the related statements
of income, comprehensive income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements (pages II-93 through II-113)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Georgia Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-82
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 2001 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 2001 earnings totaled $610 million, representing a $51
million (9.1 percent) increase over 2000. Although operating income is lower due
to the impact of mild weather on retail revenues, overall net income improved
due to lower financing costs and non-operating expenses and a lower effective
tax rate resulting from various factors including property donations and
positive resolution of outstanding tax issues. The Company's 2000 earnings
totaled $559 million, representing an $18 million (3.3 percent) increase over
1999. This earnings increase was primarily due to higher retail and wholesale
sales and continued control of operating expenses, partially offset by
additional accelerated amortization of regulatory assets allowed under the
second year of a Georgia Public Service Commission (GPSC) three-year retail rate
order.
Revenues
Operating revenues in 2001 and the amount of change from the prior year are as
follows:
Increase
(Decrease)
From Prior Year
Amount -------------------
2001 2001 2000
---- -------------------
Retail - (in millions)
Base revenues $3,102 $(17) $ 84
Fuel cost recovery 1,247 49 183
- -------------------------------------------------------------------
Total retail 4,349 32 267
- -------------------------------------------------------------------
Sales for resale -
Non-affiliates 366 68 88
Affiliates 100 4 20
- -------------------------------------------------------------------
Total sales for resale 466 72 108
- -------------------------------------------------------------------
Other operating revenues 151 (9) 39
- -------------------------------------------------------------------
Total operating revenues $4,966 $95 $414
===================================================================
Percent change 2.0% 9.3%
- -------------------------------------------------------------------
Retail base revenues of $3.1 billion in 2001 decreased $17 million (0.5
percent) from 2000 primarily due to a 2.5 percent decrease in retail sales from
the prior year. Milder-than-normal weather and a slowdown in the economy
contributed to the decline in such sales. Retail base revenues of $3.1 billion
in 2000 increased $84 million (2.8 percent) from 1999 primarily due to a 4.9
percent increase in sales. Under the prior GPSC retail rate order, the Company
recorded $44 million of revenue subject to refund for estimated earnings above
12.5 percent retail return on common equity in 2000. These refunds were made to
customers in 2001. See Note 3 to the financial statements under "Retail Rate
Orders" for additional information.
Electric rates include provisions to adjust billings for fluctuations in
fuel costs, the energy component of purchased power costs, and certain other
costs. Under these fuel cost recovery provisions, fuel revenues generally equal
fuel expenses -- including the fuel component of purchased energy -- and do not
affect net income. However, cash flow is affected by the untimely recovery of
these receivables. As of December 31, 2001, the Company had $162 million in
underrecovered fuel costs. The Company is currently collecting these
underrecovered fuel costs under a GPSC rate order issued on May 24, 2001. The
fuel cost recovery rate was increased effective June 2001 to allow for a
24-month recovery of the deferred underrecovered fuel costs.
Wholesale revenues from sales to non-affiliated utilities increased in 2001
and 2000 as follows:
2001 2000 1999
-----------------------------
(in millions)
Long-term contracts $ 61 $ 55 $ 55
Other sales 305 243 155
- -------------------------------------------------------------
Total $366 $298 $210
=============================================================
Revenues from long-term contracts increased slightly in 2001 due to
increased energy sales while remaining constant in 2000. See Note 7 to the
financial statements for further information regarding these sales. Revenues
from other non-affiliated sales increased $62 million (25.5 percent) primarily
due to increases in off-system sale transactions that were generally offset by
corresponding purchase transactions. These transactions had no significant
effect on income.
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 do not have a significant impact on earnings.
Other operating revenues in 2001 decreased $9 million (5.3 percent)
primarily due to lower gains on the sale of generating plant emission
allowances, partially offset by increased revenues from the transmission of
electricity and from the rental of electric equipment and property. Other
II-83
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
operating revenues in 2000 increased $39 million (33 percent) primarily due to
increased revenues from the transmission of electricity and gains on the sale of
generating plant emission allowances. Under a GPSC order, $28 million of the
gains on emission allowance sales in 2000 were used to reduce recoverable fuel
costs and, as such, did not affect earnings.
Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:
Percent Change
----------------------
2001
KWH 2001 2000
--------- ------------------------
(in billions)
Residential 20.1 (2.8)% 6.6%
Commercial 26.5 3.4 8.1
Industrial 25.4 (8.0) 0.9
Other 0.6 2.5 3.2
------
Total retail 72.6 (2.5) 4.9
------
Sales for resale -
Non-affiliates 8.1 25.5 27.7
Affiliates 3.1 28.7 35.6
------
Total sales for resale 11.2 26.3 29.8
------
Total sales 83.8 0.5 7.1
======
- ------------------------------------------------------------
Residential sales decreased 2.8 percent due to milder-than-normal weather.
Commercial sales increased 3.4 percent due to a 2.8 percent increase in
customers, while industrial sales decreased 8.0 percent due to an economic
slowdown. Residential and commercial sales increased 6.6 percent and 8.1
percent, respectively, in 2000 due to warmer summer temperatures and colder
winter weather. Strong regional economic growth was also a factor in the
increase in commercial sales. Industrial sales remained fairly constant.
Expenses
Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net KWH generated were as follows:
2001 2000 1999
--------------------------
Total generation
(billions of KWH) 68.9 73.6 69.3
Sources of generation
(percent) --
Coal 74.9 75.8 75.5
Nuclear 23.2 21.2 21.6
Hydro 1.4 0.8 1.0
Oil and gas 0.5 2.2 1.9
Average cost of fuel per net
KWH generated
(cents) -- 1.38 1.39 1.34
- --------------------------------------------------------------
Fuel expense decreased 7.7 percent due to a decrease in generation because
of lower energy demands and a slightly lower average cost of fuel. Fuel expense
increased 10.7 percent in 2000 due to an increase in generation to meet higher
energy demands, a decrease in generation from hydro plants, and a higher average
cost of fuel.
Purchased power expense increased $175 million (29.4 percent) in 2001
primarily due to an increase in off-system purchases used to meet off-system
sales commitments. These transactions had no significant effect on earnings.
Purchased power expense in 2000 increased $206 million (53 percent) over the
prior year due to higher retail energy demands and off-system purchase
transactions used to meet off-system sales transactions.
In 2001, other operation and maintenance expenses increased $41 million
(3.4%) due to additional severance costs, increased scheduled generating plant
maintenance, and higher uncollectible account expense. Other operation and
maintenance expenses in 2000 increased slightly over those in 1999. Increased
line maintenance, customer assistance and sales expense, and severance costs
were partially offset by decreased generating plant maintenance and decreased
employee benefit provisions.
Depreciation and amortization decreased $19 million in 2001 primarily due
to lower accelerated amortization under the third year of a GPSC retail rate
order. Depreciation and amortization increased $66 million in 2000 primarily due
to $50 million of additional accelerated amortization of regulatory assets
required under the second year of the GPSC retail rate order and increased plant
in service.
II-84
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
Other, net increased in 2001 due to gains realized on sales of assets and a
decrease in charitable contributions. Other, net decreased in 2000 due to an
increase in charitable contributions.
Interest expense, net decreased in 2001 primarily due to lower interest
rates that offset new financing costs. Interest expense, net increased in 2000
due to the issuance of additional senior notes during 2000. The Company
refinanced or retired $775 million and $179 million of securities in 2001 and
2000, respectively. Distributions on preferred securities of subsidiary
companies remained unchanged in 2001 and decreased $7 million in 2000 due to the
redemption of $100 million of preferred securities in December 1999.
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
General
The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including regulatory matters and energy sales.
Growth in energy sales is subject to a number of factors which
traditionally have included changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, weather,
competition, initiatives to increase sales to existing customers, and the rate
of economic growth in the Company's service area.
In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income
of approximately $60 million in 2001. Future pension income is dependent on
several factors including trust earnings and changes to the plan. For the
Company, pension income is a component of the regulated rates and does not have
a significant effect on net income. For additional information, see Note 2 to
the financial statements.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
State of Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC under cost-based regulatory principles.
On December 20, 2001, the GPSC approved a new three-year retail rate order
for the Company ending December 31, 2004. Under the terms of the order, earnings
will be evaluated annually against a retail return on common equity range of 10
percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent
return will be applied to rate refunds, with the remaining one-third retained by
the Company. Retail rates were decreased by $118 million effective January 1,
2002. Pursuant to a previous three-year accounting order, the Company recorded
$336 million of accelerated cost amortization and interest thereon which has
been credited to a regulatory liability account as mandated by the GPSC. Under
the new rate order, the accelerated amortization and the interest will be
amortized equally over three years as a credit to expense beginning in 2002. The
Company will not file for a general base rate increase unless its projected
retail return on common equity falls below 10 percent. Georgia Power is required
to file a general rate case on July 1, 2004, in response to which the GPSC would
be expected to determine whether the rate order should be continued, modified,
or discontinued. See Note 3 to the financial statements under "Retail Rate
Orders" for additional information.
The Company has entered into power purchase agreements which will result in
higher capacity and operating and maintenance payments in future years. Under
the new retail rate order, these costs will be reflected in rates evenly over
the next three years. See Note 4 to the financial statements under "Purchased
Power Commitments" for additional information.
II-85
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
Georgia Power had three new generation projects under construction during
2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt
combustion turbine facility; two combined cycle units totaling 1,132 megawatts
at Plant Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle
facility. All three of these projects have been transferred to Southern Power
Company, a new Southern Company subsidiary formed in 2001 to construct, own, and
manage wholesale generating assets in the Southeast. The ten Dahlberg units and
two Goat Rock units were transferred in 2001 and the transfer of the two Wansley
units was completed in January 2002.
The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. See "Environmental Issues" for further discussion of these matters.
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are affected by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers.
Although the Energy Act does not permit retail customer access, it has been
a major catalyst for recent restructuring and consolidations taking place within
the utility industry. Numerous federal and state initiatives are in varying
stages that promote wholesale and retail competition. Among other things, these
initiatives allow customers to choose their electricity provider. Some states
have approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While restructuring and competition
initiatives have been discussed in Georgia, none have been enacted. Enactment
would require numerous issues to be resolved, including significant ones
relating to recovery of any stranded investments, full cost recovery of energy
produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation. The Company
does compete with other electric suppliers within the state. In Georgia, most
new retail customers with at least 900 kilowatts of connected load may choose
their electricity supplier.
In December 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encouraged utilities owning transmission systems to form RTOs on a voluntary
basis. Southern Company has submitted a series of status reports informing the
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing an RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to
have a material impact on Georgia Power's financial statements. The outcome of
this matter cannot now be determined.
Accounting Policies
Critical Policy
Georgia Power's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's 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, including plant, have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
II-86
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
New Accounting Standards
Effective January 2001, Georgia Power adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change -- effective April
1, 2002 -- in accounting for certain contracts related to fuel supplies that
contain quantity options. These contracts will be accounted for as derivatives
and marked to market. However, due to the existence of specific cost-based fuel
recovery clauses for the Company, this change is not expected to have a material
impact on net income.
In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets (but not
those acquired in a business combination) should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No. 142 effective January 1, 2002 with
no material impact on the Company's financial statements.
Also, in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning nuclear
plants. The liability for an asset's future retirement must be recorded in the
period in which the liability is incurred. The cost must be capitalized as part
of the related long-lived asset and depreciated over the asset's useful life.
Changes in the liability resulting from the passage of time will be recognized
as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The
Company has not yet quantified the impact of adopting Statement No. 143 on its
financial statements.
FINANCIAL CONDITION
Plant Additions
In 2001, gross utility plant additions were $1.4 billion. These additions were
primarily related to transmission and distribution facilities, the purchase of
nuclear fuel, and the construction of additional combustion turbine and combined
cycle units. The funds needed for gross property additions are currently
provided from operations, short-term and long-term debt, and capital
contributions from Southern Company. The Statements of Cash Flows provide
additional details.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are certain physical electricity sale contracts that could
require collateral -- but not termination -- in the event of a credit rating
change to below investment grade. At December 31, 2001, the maximum potential
collateral requirements were approximately $112 million.
Exposure to Market Risks
The Company is exposed to market risks, including changes in interest rates,
currency exchange rates, and certain commodity prices. To manage the volatility
attributable to these exposures, the Company nets the exposures to take
advantage of natural offsets and enters into various derivative transactions for
the remaining exposures pursuant to the Company's policies in areas such as
counterparty exposure and hedging practices. Company policy is that derivatives
are to be used primarily for hedging purposes. Derivative positions are
monitored using techniques that include market valuation and sensitivity
analysis.
The Company's market risk exposures relative to interest rate changes have
not changed materially compared to the previous reporting period. In addition,
the Company is not aware of any facts or circumstances that would significantly
affect such exposures in the near term.
II-87
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
If the Company sustained a 100 basis point change in interest rates for all
variable rate long-term debt, the change would affect annualized interest
expense by approximately $13 million at December 31, 2001. Based on the
Company's overall interest rate exposure at December 31, 2001, including
derivative and other interest rate sensitive instruments, a near-term 100 basis
point change in interest rates would not materially affect the Company's
financial statements.
Due to cost-based rate regulations, the Company has limited exposure to
market volatility in interest rates, commodity fuel prices, and prices of
electricity. To mitigate residual risks relative to movements in electricity
prices, the Company entered into fixed price contracts for the purchase and sale
of electricity through the wholesale electricity market and to a lesser extent
similar contracts for gas purchases. Realized gains and losses are recognized in
the Statements of Income as incurred. At December 31, 2001, exposure from these
activities was not material to the Company's financial statements. Fair value of
changes in energy trading contracts and year-end valuations are as follows:
Changes During the Year
- ----------------------------------------------------
Fair Value
- ----------------------------------------------------
(in millions)
Contracts beginning of year $0.9
Contracts realized or settled (0.6)
New contracts at inception -
Changes in valuation techniques -
Current period changes 0.1
- ----------------------------------------------------
Contracts end of year $0.4
===================================================
All of these contracts are actively quoted and mature within one year. For
additional information, see Note 1 to the financial statements under "Financial
Instruments."
Financing Activities
In 2001, the Company's financing costs decreased due to lower interest rates
despite the issuance of new debt during the year. New issues during 1999 through
2001 totaled $1.9 billion and retirement or repayment of higher-cost securities
totaled $1.7 billion.
The proceeds from assets transferred to Southern Power were used to reduce
short-term debt and return capital to the Southern Company that was used during
the construction of these projects.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 1999 through 2001, as of year-end, were as
follows:
2001 2000 1999
--------------------------------
Composite interest rate
on long-term debt 4.26% 5.90% 5.48%
Composite preferred
stock dividend rate 4.60 4.60 4.60
Composite preferred
securities dividend rate 7.49 7.49 7.49
- ----------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations remained constant in 2001.
The Company estimates that construction expenditures for the years 2002
through 2004 will total $1.0 billion, $0.8 billion, and $0.8 billion,
respectively. Investments primarily in additional transmission and distribution
facilities and equipment to comply with environmental requirements are planned.
Cash requirements for redemptions announced and maturities of long-term
debt are expected to total $666 million during 2002 through 2004.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
decommissioning costs. The amount to be funded under the new GPSC rate order is
$8.7 million each year in 2002, 2003, and 2004. For additional information
concerning nuclear decommissioning costs, see Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning."
Sources of Capital
The Company expects to meet future capital requirements primarily using funds
generated from operations and equity funds from Southern Company and by the
issuance of new debt and equity securities, term loans, and short-term
borrowings. The Company plans to request new financing authority from the GPSC
in early 2002 to allow for the issuance of new long-term securities. To meet
short-term cash needs and contingencies, the Company had approximately $1.8
billion of unused credit arrangements with banks at the beginning of 2002. See
Note 9 to the financial statements under "Bank Credit Arrangements" for
additional information.
II-88
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $707.6 million of commercial
paper.
Recently, the Company has relied on the issuance of unsecured debt and
trust preferred securities, in addition to unsecured pollution control bonds
issued for its benefit by public authorities, to meet its long-term external
financing requirements. In years past, the Company issued first mortgage bonds,
mortgage backed pollution control bonds and preferred stock to fund its external
requirements. The amount outstanding of these securities has been steadily
declining during the last four years.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $666
million will be required by the end of 2004 for maturities of long-term debt.
Also, the Company will continue to retire higher-cost debt and preferred
securities and replace these obligations with lower-cost capital if market
conditions permit.
These capital requirements, lease obligations, and purchase commitments --
discussed in Notes 4 and 9 to the financial statements -- are as follows:
2002 2003 2004
- ---------------------------------------------------------------
(in millions)
Bonds -
First mortgage $ 2 $ - $ -
Pollution control 8 - -
Notes 300 350 -
Leases -
Capital 2 2 2
Operating 15 15 15
Purchase commitments
Fuel 1,234 1,115 617
Purchased power 163 223 278
- ---------------------------------------------------------------
At the beginning of 2002, Georgia Power had not used any of its available
credit arrangements. Credit arrangements are as follows:
Expires
----------------------------
Total Unused 2002 2003 & beyond
------------------------------------------------------
(in millions)
$1,765 $1,765 $1,265 $500
------------------------------------------------------
ENVIRONMENTAL ISSUES
Clean Air Legislation
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company's subsidiaries,
including the Company. Reductions in sulfur dioxide and nitrogen oxide emissions
from fossil-fired generating plants were required in two phases. Phase I
compliance began in 1995.
Southern Company's subsidiaries, including the Company, achieved Phase I
compliance at the affected units by primarily switching to low-sulfur coal and
with some equipment upgrades. Construction expenditures for the Company's Phase
I compliance totaled approximately $167 million.
Phase II sulfur dioxide compliance was required in 2000. Southern Company's
subsidiaries, including the Company, used emission allowances and fuel switching
to comply with Phase II requirements. Also, equipment to control nitrogen oxide
emissions was installed on additional system fossil-fired units as necessary to
meet Phase II limits and ozone non-attainment requirements for metropolitan
Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment
requirements increased total construction expenditures for the Company through
2000 by approximately $39 million.
In 2000, the State of Georgia established new emission limits designed to
help bring the Atlanta area into compliance with the national one-hour standard
for ground-level ozone. The limits include new emission standards for seven of
the Company's generating stations and will go into effect in May 2003.
Construction expenditures for the Company's compliance with these new rules are
currently estimated at approximately $699 million with a total of $345 million
remaining to be spent.
II-89
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the
national ambient air quality standards for ozone and particulate matter. This
revision made the standards significantly more stringent. In the subsequent
litigation of these standards, the U.S. Supreme Court found the EPA's
implementation program for the new ozone standard unlawful and remanded it to
the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals
is considering other legal challenges to these standards. If the standards are
eventually upheld, implementation could be required by 2007 to 2010.
In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rule affects 21 states including
Georgia. Compliance is required by May 31, 2004. The EPA proposed rules for
Georgia on February 13, 2002. The EPA's proposal includes a May 1, 2005
implementation date for Georgia. The Company plans to demonstrate compliance
based largely on NOx controls already installed to meet the Atlanta
non-attainment requirements, coupled with the purchase of NOx credits within a
NOx trading market.
In December 2000, having completed its utility study for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is to be developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and regulations are scheduled to be finalized by the end of
2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional
Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: control strategies to reduce regional
haze; limits on pollutant discharges to impaired waters; cooling water intake
restrictions; and hazardous waste disposal requirements. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
Environmental Protection Agency Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. 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
Bowen and Scherer plants. 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 two plants. 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
II-90
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
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.
The case against the Company has been stayed since the spring of 2001
pending a ruling by the federal Court of Appeals for the Eleventh Circuit in the
appeal of a very similar Clean Air Act / New Source Review enforcement action
brought by EPA against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on Georgia Power, the Company is a party to that case as well. The
federal court in Georgia is currently considering a motion by the EPA to reopen
the case. The Company has opposed that motion. An adverse outcome of this matter
could require substantial capital expenditures that cannot be determined at this
time and could 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.
Other Environmental Issues
The Company must comply with other environmental laws and regulations that cover
the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. The Company conducts studies to determine the extent of any
required clean-up and has recognized in the financial statements costs to clean
up known sites. These costs for the Company amounted to $0.6 million in 2001 and
$4 million in both 2000 and 1999. Additional sites may require environmental
remediation for which the Company may be liable for all or a portion of required
clean-up costs. See Note 3 to the financial statements under "Other
Environmental Contingencies" for information regarding the Company's potentially
responsible party status at sites in Georgia.
Several major pieces of environmental legislation are periodically
considered for reauthorization or amendment by Congress. These include: the
Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response,
Compensation, and Liability Act; the Resource Conservation and Recovery Act; the
Toxic Substances Control Act; and the Endangered Species Act. Changes to these
laws could affect many areas of the Company's operations. The full impact of any
such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if any
- -- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
The Company's 2001 Annual Report includes forward-looking statements in addition
to historical information. In some cases, forward-looking statements can be
identified by terminology such as "may," "will," "could," "should," "expects,"
"plans," "anticipates," "believes," "estimates," "predicts," "projects,"
"potential" or "continue" or the negative of these terms or other comparable
terminology. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking statements; accordingly, there can be no assurance that such
indicated results will be realized.
These factors include the impact of recent and future federal and state
regulatory change, including legislative and regulatory initiatives regarding
deregulation and restructuring of the electric utility industry and also changes
in environmental and other laws and regulations to which the Company is subject,
as well as changes in application of existing laws and regulations; current and
future litigation, including the pending EPA civil action and the race
discrimination litigation against the Company; the effect, extent, and timing of
the entry of additional competition in the markets in which the Company
operates; the impact of fluctuations in commodity prices, interest rates, and
customer demand; state and federal rate regulations; political, legal, and
economic conditions and developments in the United States; the effects of, and
changes in economic conditions in the areas in which the Company operates;
internal restructuring or other restructuring options that may be pursued by the
Company; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or
II-91
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report
beneficial; the direct or indirect effects on the Company's business resulting
from the terrorist incidents on September 11, 2001, or any similar such
incidents or responses to such incidents; financial market conditions and the
results of financing efforts; the ability of the Company to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports (including
Form 10-K) filed from time to time by the Company with the Securities and
Exchange Commission.
II-92
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $4,349,312 $4,317,338 $4,050,088
Sales for resale --
Non-affiliates 366,085 297,643 210,104
Affiliates 99,411 96,150 76,426
Other revenues 150,986 159,487 120,057
- -------------------------------------------------------------------------------------------------------------
Total operating revenues 4,965,794 4,870,618 4,456,675
- -------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 939,092 1,017,878 919,876
Purchased power --
Non-affiliates 442,196 356,189 214,573
Affiliates 329,232 239,815 174,989
Other 810,043 795,458 784,359
Maintenance 430,413 404,189 411,983
Depreciation and amortization 600,631 619,094 552,966
Taxes other than income taxes 202,483 204,527 202,853
- -------------------------------------------------------------------------------------------------------------
Total operating expenses 3,754,090 3,637,150 3,261,599
- -------------------------------------------------------------------------------------------------------------
Operating Income 1,211,704 1,233,468 1,195,076
Other Income (Expense):
Interest income 4,264 2,629 5,583
Equity in earnings of unconsolidated subsidiaries 4,178 3,051 2,721
Other, net (2,816) (50,495) (47,986)
- -------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 1,217,330 1,188,653 1,155,394
- -------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest expense, net 183,879 208,868 194,869
Distributions on preferred securities of subsidiaries 59,104 59,104 65,774
- -------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 242,983 267,972 260,643
- -------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 974,347 920,681 894,751
Income taxes 363,599 360,587 351,639
- -------------------------------------------------------------------------------------------------------------
Net Income Before Cumulative Effect of
Accounting Change 610,748 560,094 543,112
Cumulative effect of accounting change --
less income taxes of $162 thousand 257 - -
- -------------------------------------------------------------------------------------------------------------
Net Income 611,005 560,094 543,112
Dividends on Preferred Stock 670 674 1,729
- -------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 610,335 $ 559,420 $ 541,383
=============================================================================================================
The accompanying notes are an integral part of these statements.
II-93
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 611,005 $ 560,094 $ 543,112
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 697,143 712,960 663,878
Deferred income taxes and investment tax credits, net (48,329) (28,961) (34,930)
Other, net (92,403) (51,501) (42,179)
Changes in certain current assets and liabilities --
Receivables, net 60,914 (108,621) 21,665
Fossil fuel stock (103,296) 26,835 (22,165)
Materials and supplies (15,628) (9,715) (10,417)
Accounts payables (15,406) 64,412 13,095
Energy cost recovery, retail (29,839) (95,235) (26,862)
Other (2,999) (9,092) 90,788
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,061,162 1,061,176 1,195,985
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,389,751) (1,078,163) (790,464)
Sales of property 534,760 - -
Other (4,774) (5,450) (27,454)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (859,765) (1,083,613) (817,918)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase in notes payable, net 43,698 67,598 295,389
Proceeds --
Senior notes 600,000 300,000 100,000
Pollution control bonds 404,535 78,725 238,000
Preferred securities - - 200,000
Capital contributions from parent company 225,060 301,514 155,777
Retirements --
First mortgage bonds (390,140) (100,000) (404,000)
Pollution control bonds (385,035) (78,725) (235,000)
Preferred securities - - (100,000)
Preferred stock - (383) (36,231)
Capital distributions to parent company (160,000) - -
Payment of preferred stock dividends (578) (751) (984)
Payment of common stock dividends (527,300) (549,600) (543,000)
Other (17,747) (1,231) (29,630)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (207,507) 17,147 (359,679)
- -----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (6,110) (5,290) 18,388
Cash and Cash Equivalents at Beginning of Year 29,370 34,660 16,272
- -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $23,260 $29,370 $34,660
- -----------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 234,456 $ 265,373 $ 247,050
Income taxes (net of refunds) 381,995 392,310 394,457
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-94
BALANCE SHEETS
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 23,260 $ 29,370
Receivables --
Customer accounts receivable 376,322 465,249
Underrecovered retail fuel clause revenue 161,462 131,623
Other accounts and notes receivable 129,073 156,143
Affiliated companies 87,786 13,312
Accumulated provision for uncollectible accounts (8,895) (5,100)
Fossil fuel stock, at average cost 202,759 99,463
Materials and supplies, at average cost 279,237 263,609
Other 125,246 97,515
- ------------------------------------------------------------------------------------------------------------------
Total current assets 1,376,250 1,251,184
- ------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 16,886,399 16,469,706
Less accumulated provision for depreciation 7,243,209 6,914,512
- ------------------------------------------------------------------------------------------------------------------
9,643,190 9,555,194
Nuclear fuel, at amortized cost 112,771 120,570
Construction work in progress (Note 4) 883,285 652,264
- ------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 10,639,246 10,328,028
- ------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4) 35,209 29,569
Nuclear decommissioning trusts 364,180 375,666
Other 29,618 29,745
- ------------------------------------------------------------------------------------------------------------------
Total other property and investments 429,007 434,980
- ------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 543,584 565,982
Prepaid pension costs 228,259 147,271
Debt expense, being amortized 58,165 53,748
Premium on reacquired debt, being amortized 173,724 173,610
Other 117,706 120,964
- ------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,121,438 1,061,575
- ------------------------------------------------------------------------------------------------------------------
Total Assets $13,565,941 $13,075,767
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-95
BALANCE SHEETS
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2001 2000
- --------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 9) $ 311,620 $ 1,808
Notes payable 747,537 703,839
Accounts payable --
Affiliated 109,591 117,168
Other 409,253 397,550
Customer deposits 83,172 78,540
Taxes accrued --
Income taxes 35,247 5,151
Other 125,807 137,511
Interest accrued 46,942 47,244
Vacation pay accrued 41,830 38,865
Other 112,686 137,565
- --------------------------------------------------------------------------------------------------------------------
Total current liabilities 2,023,685 1,665,241
- --------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 2,961,726 3,041,939
- --------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,163,959 2,182,783
Deferred credits related to income taxes (Note 8) 229,216 247,067
Accumulated deferred investment tax credits (Note 8) 337,482 352,282
Employee benefits provisions 207,795 191,587
Other 440,774 341,505
- --------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,379,226 3,315,224
- --------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 789,250 789,250
- --------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 14,569 14,569
- --------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 4,397,485 4,249,544
- --------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $13,565,941 $13,075,767
====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-96
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds
Maturity Interest Rates
- -------- -------------
April 1, 2003 6.625% $ - $ 200,000
August 1, 2003 6.35% - 75,000
2005 6.07% 1,860 10,000
2008 6.875% - 50,000
2025 7.70% - 57,000
- --------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,860 392,000
- --------------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
Variable rate (1.98125% at 1/1/02) due February 22, 2002 300,000 300,000
5.75% due January 31, 2003 200,000 -
5.25% due May 8, 2003 150,000 -
5.50% due December 1, 2005 150,000 150,000
6.20% due February 1, 2006 150,000 -
6.70% due March 1, 2011 100,000 -
6.60% due December 31, 2038 200,000 200,000
6.625% due March 31, 2039 100,000 100,000
6.875% due December 31, 2047 145,000 145,000
- --------------------------------------------------------------------------------------------------------------
Total senior notes payable 1,495,000 895,000
- --------------------------------------------------------------------------------------------------------------
Other long-term debt -- (Note 9)
Pollution control revenue bonds --
Maturity Interest Rates
------- -------------
2005 5.00% - 57,000
2011 Variable (1.90% to 1.95% at 1/1/02) 10,450 10,450
2012-2016 4.20% to 5.00% 164,590 -
2018-2021 6.00% to 6.25% 7,800 23,225
2018 Variable (2.00% at 1/1/02) 19,500 -
2023-2025 4.90% to 6.75% 28,065 298,535
2022-2026 Variable (1.75% to 1.95% at 1/1/02) 669,480 683,555
2029 Variable (1.90% to 1.95% at 1/1/02) 144,700 144,700
2030-2031 4.53% to 5.25% 137,570 78,725
2032-2034 Variable (1.75% to 1.95% at 1/1/02) 140,000 140,000
2032-2034 4.45% to 5.45% 371,535 238,000
- --------------------------------------------------------------------------------------------------------------
Total other long-term debt 1,693,690 1,674,190
- --------------------------------------------------------------------------------------------------------------
Capital lease obligations (Note 9) 83,371 85,179
- --------------------------------------------------------------------------------------------------------------
Unamortized debt discount, net (575) (2,622)
- --------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest)
requirement -- $139.5 million) 3,273,346 3,043,747
Less amount due within one year (Note () 311,620 1,808
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year $ 2,961,726 $ 3,041,939 36.3 % 37.6 %
- -----------------------------------------------------------------------------------------------------------------------------------
II-97
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 6.85% $ 200,000 $ 200,000
$25 liquidation value -- 7.60% 175,000 175,000
$25 liquidation value -- 7.75% 189,250 189,250
$25 liquidation value -- 7.75% 225,000 225,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59.1 million) 789,250 789,250 9.6 9.7
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 145,689 shares at December 31, 2001
Outstanding -- 145,689 shares at December 31, 2000
$100 stated value --
4.60% 14,569 14,569
- -----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $0.7 million) 14,569 14,569 0.2 0.2
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares 344,250 344,250
Paid-in capital 2,182,557 2,117,497
Premium on preferred stock 40 40
Other comprehensive income (153) -
Retained earnings (Note 9) 1,870,791 1,787,757
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statements) 4,397,485 4,249,544 53.9 52.5
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,163,030 $ 8,095,302 100.0 % 100.0 %
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-98
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (Loss) Total
- ------------------------------------------------------------------------------------------------------------------------------
Balance at January 1, 1999 $344,250 $1,660,206 $158 $1,779,558 $ - $3,784,172
Net income after dividends on preferred stock - - - 541,383 - 541,383
Capital contributions from parent company - 155,777 - - - 155,777
Cash dividends on common stock - - - (543,000) - (543,000)
Preferred stock transactions, net - - (118) (4) - (122)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 344,250 1,815,983 40 1,777,937 - 3,938,210
Net income after dividends on preferred stock - - - 559,420 - 559,420
Capital contributions from parent company - 301,514 - - - 301,514
Cash dividends on common stock - - - (549,600) - (549,600)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 344,250 2,117,497 40 1,787,757 - 4,249,544
Net income after dividends on preferred stock - - - 610,335 - 610,335
Capital contributions from parent company - 225,060 - - - 225,060
Capital distributions to parent company (160,000) (160,000)
Other comprehensive income - - - - (153) (153)
Cash dividends on common stock - - - (527,300) - (527,300)
Preferred stock transactions, net - - - (1) - (1)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $344,250 $2,182,557 $40 $1,870,791 ($153) $4,397,485
===============================================================================================================================
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $ 610,335 $ 559,420 $ 541,383
Other comprehensive income:
Cumulative effect of accounting change, net of tax 286 - -
Current period changes in fair value, net of tax (439) - -
- ---------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 610,182 $ 559,420 $ 541,383
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-99
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2001 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, a system service company (SCS),
Southern Communications Services (Southern LINC), Southern Nuclear Operating
Company (Southern Nuclear), Southern Power Company (Southern Power), and other
direct and indirect subsidiaries. The operating companies --Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company-- provide electric service in four
southeastern states. Contracts among the operating companies -- related to
jointly owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission. SCS provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Power was established in 2001 to construct, own, and manage Southern
Company's competitive generation assets and sell electricity at market-based
rates in the wholesale market.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows accounting principles generally accepted
in the United States and complies with the accounting policies and practices
prescribed by the respective regulatory commissions. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States requires the use of estimates, and the actual results may
differ from these estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Affiliate Transactions
The Company has an agreement with 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 operations. Costs for these services amounted to $285 million, $269
million, and $253 million during 2001, 2000, and 1999, respectively.
The Company has an agreement with Southern Nuclear under which the
following nuclear-related services are rendered to the Company at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting and
statistical, employee relations, and systems and procedures services; strategic
planning and budgeting services; and other services with respect to business and
operations. Costs for these services amounted to $281 million in both 2001 and
2000 and $270 million in 1999.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues associated with
certain costs that are expected to be recovered from customers through the
ratemaking process. Regulatory liabilities represent probable future reductions
in revenues associated with amounts that are expected to be credited to
customers through the ratemaking process. See Note 3 under "Retail Rate Orders"
for additional information regarding the disposition of the regulatory liability
for the accelerated cost recovery recorded under the retail rate order that
ended December 31, 2001. Regulatory assets and (liabilities) reflected in the
Company's Balance Sheets at December 31 relate to the following:
II-100
NOTES (continued)
Georgia Power Company 2001 Annual Report
2001 2000
----------------------
(in millions)
Deferred income taxes $ 544 $ 566
Deferred income tax credits (229) (247)
Premium on reacquired debt 174 174
Corporate building lease 54 55
Vacation pay 52 49
Postretirement benefits 28 30
Department of Energy assessments 18 21
Deferred nuclear outage costs 24 28
Accelerated cost recovery and
interest (336) (230)
Other, net 16 23
--------------------------------------------------------------
Total $ 345 $ 469
===============================================================
In the event that a portion of the Company's operations is no longer
subject to the provisions of 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 value.
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 Georgia, and to wholesale customers in the Southeast.
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 averaged less than 1 percent of revenues.
Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is
used. The Company's fuel cost recovery mechanism includes provisions to adjust
billings for fluctuations in fuel costs, the energy component of purchased power
costs, and certain other costs. Revenues are adjusted for differences between
recoverable fuel costs and amounts actually recovered in current rates.
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 $75
million in each of 2001 and 2000 and $74 million in 1999. The Company has
contracts with the U.S. Department of Energy (DOE) that provide for the
permanent disposal of used nuclear fuel. The DOE failed to begin disposing of
used nuclear fuel in January 1998 as required by the contracts, and the Company
is pursuing legal remedies against the government for breach of contract.
Sufficient pool storage capacity is available at Plant Vogtle to maintain
full-core discharge capability for both units until the year 2014. To maintain
pool discharge capability at Plant Hatch, effective June 2000, an on-site dry
storage facility for Plant Hatch became operational. Sufficient dry storage
capacity is believed to be available to continue dry storage operations at Plant
Hatch through the life of the plant. Procurement of on-site dry storage capacity
at Plant Vogtle will commence in sufficient time to maintain pool full-core
discharge capability.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is to be funded in
part by a special assessment on utilities with nuclear plants. The 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 -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 2001 to be approximately $16 million. This obligation is recorded
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
3.3 percent in 2001, 2000, and 1999. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its original
cost -- together with the cost of removal, less salvage -- is charged to
accumulated depreciation. 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 costs of decommissioning nuclear
facilities and removal of other facilities.
Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial power reactors to establish a plan for providing, with
II-101
NOTES (continued)
Georgia Power Company 2001 Annual Report
reasonable assurance, funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Earnings on the trust
funds are considered in determining decommissioning expense. 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.
The Company periodically conducts site-specific studies to estimate the
actual cost of decommissioning its nuclear generating facilities. 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 its retirement
date. The estimated site study costs based on the most current study and
ultimate costs assuming an inflation rate of 4.7 percent for the Company's
ownership interests are as follows:
Plant Plant
Hatch Vogtle
--------------------
Site study basis (year) 2000 2000
Decommissioning periods:
Beginning year 2014 2027
Completion year 2042 2045
- -------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $486 $420
Non-radiated structures 37 48
- -------------------------------------------------------------
Total $523 $468
=============================================================
(in millions)
Ultimate costs:
Radiated structures $1,004 $1,468
Non-radiated structures 79 166
- -------------------------------------------------------------
Total $1,083 $1,634
=============================================================
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 the NRC requirements, changes in the assumptions
used in making the estimates, changes in regulatory requirements, changes in
technology, and changes in costs of labor, materials, and equipment.
Annual provisions for nuclear decommissioning expense are based on an
annuity method as approved by the GPSC. The amounts expensed in 2001 and fund
balances as of December 31, 2001 were:
Plant Plant
Hatch Vogtle
- ----------------------------------------------------------------
(in millions)
Amount expensed in 2001 $20 $9
================================================================
(in millions)
Accumulated provisions:
External trust funds, at fair value $229 $135
Internal reserves 20 12
- ----------------------------------------------------------------
Total $249 $147
================================================================
Effective January 1, 2002, the GPSC decreased the annual provision for
decommissioning expenses to $8 million. This amount is based on the NRC generic
estimate to decommission the radioactive portion of the facilities as of 2000
of $383 million and $282 million for Plants Hatch and Vogtle, respectively. The
ultimate costs associated with the 2000 NRC minimum funding requirements are
$823 million and $1.03 billion for Plants Hatch and Vogtle, respectively.
Significant assumptions include an estimated inflation rate of 4.7 percent and
an estimated trust earnings rate of 6.5 percent. The Company expects the GPSC
to periodically review and adjust, if necessary, the amounts collected in rates
for the anticipated cost of decommissioning.
In January 2002, the NRC granted the Company a 20-year extension of the
licenses for both units at Plant Hatch which permits the operation of units 1
and 2 until 2034 and 2038, respectively. The decommissioning costs disclosed
above do not reflect this extension.
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 regulated facilities. While cash is
II-102
NOTES (continued)
Georgia Power Company 2001 Annual Report
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. For the years 2001, 2000, and 1999, the average AFUDC
rates were 6.33 percent, 6.74 percent, and 5.61 percent, respectively. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 3.0 percent for 2001, 2000, and 1999.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost, less regulatory
disallowances and impairments. Original cost includes: materials; labor;
payroll-related costs such as taxes, pensions, and other benefits; and the 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.
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.
Comprehensive Income
Comprehensive income -- consisting of net income and changes in the fair value
of qualifying cash flow hedges, net of income taxes -- is presented in the
financial statements. The objective of comprehensive income is to report a
measure of all changes in common stock equity of an enterprise that result from
transactions and other economic events of the period other than transactions
with owners.
Financial Instruments
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on net
income was immaterial.
The Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, and certain
commodity prices. Gains and losses on qualifying hedges are deferred and
recognized either in income or as an adjustment to the carrying amount of the
hedged item when the transaction occurs.
The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.
The Company and its affiliates, through SCS acting as their agent, enter into
commodity related forward and option contracts to limit exposure to changing
prices on certain fuel purchases and electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales contracts
meet the definition of a derivative under Statement No. 133. In many cases,
these fuel and electricity contracts qualify for normal purchase and sale
exceptions under Statement No. 133 and are accounted for under the accrual
method. Other contracts qualify as cash flow hedges of anticipated transactions,
resulting in the deferral of related gains and losses, and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.
The Company's financial instruments for which the carrying amounts did not
approximate fair value at December 31 were as follows:
Carrying Fair
Amount Value
------------------------
Long-term debt: (in millions)
At December 31, 2001 $3,190 $3,190
At December 31, 2000 $2,959 $2,912
Preferred securities:
At December 31, 2001 $789 $782
At December 31, 2000 $789 $761
- --------------------------------------------------- ----------
The fair values for securities were based on either closing market prices
or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
II-103
NOTES (continued)
Georgia Power Company 2001 Annual Report
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
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 these employees may become
eligible for such benefits when they retire. The Company funds postretirement
trusts to the extent required by the GPSC and the FERC. In late 2000, the
Company adopted several pension and postretirement benefits plan changes that
had the effect of increasing benefits to both current and future retirees. The
measurement date for plan assets and obligations is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
2001 2000
- -----------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Expected long-term return on plan
assets 8.50 8.50
- -----------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
--------------------------
2001 2000
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,322 $1,275
Service cost 35 32
Interest cost 101 94
Benefits paid (74) (67)
Actuarial gain and
employee transfers 64 (12)
- ---------------------------------------------------------------
Balance at end of year $1,448 $1,322
===============================================================
Plan Assets
---------------------------
2001 2000
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $2,464 $2,107
Actual return on plan assets (356) 385
Benefits paid (62) (58)
Employee transfers (2) 30
- ----------------------------------------------------------------
Balance at end of year $2,044 $2,464
================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $ 596 $ 1,142
Unrecognized transition obligation (22) (26)
Unrecognized prior service cost 98 44
Unrecognized net actuarial gain (444) (1,013)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 228 $ 147
===============================================================
Components of the plan's net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 35 $ 33 $ 33
Interest cost 101 94 86
Expected return on plan assets (168) (152) (137)
Recognized net actuarial gain (31) (26) (17)
Net amortization 3 (1) -
- ---------------------------------------------------------------
Net pension income $ (60) $ (52) $ (35)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
-------------------------
2001 2000
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $495 $438
Service cost 9 7
Interest cost 39 36
Benefits paid (24) (21)
Actuarial gain and
employee transfers 23 35
- --------------------------------------------------------------
Balance at end of year $542 $495
==============================================================
II-104
NOTES (continued)
Georgia Power Company 2001 Annual Report
Plan Assets
---------------------------
2001 2000
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $198 $177
Actual return on plan assets (26) 12
Employer contributions 47 30
Benefits paid (24) (21)
- ----------------------------------------------------------------
Balance at end of year $195 $198
================================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2001 2000
- ---------------------------------------------------------------
(in millions)
Funded status $(347) $(297)
Unrecognized transition obligation 105 113
Unrecognized prior service cost 104 60
Unrecognized (gain)/loss 5 (13)
Fourth quarter contributions 27 27
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(106) $(110)
===============================================================
Components of the plans' net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in millions)
Service cost $ 9 $ 7 $ 8
Interest cost 39 36 30
Expected return on plan assets (19) (16) (10)
Recognized net actuarial loss - - 1
Net amortization 14 12 9
- ---------------------------------------------------------------
Net postretirement cost $ 43 $ 39 $38
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $54 $46
Service and interest costs 5 4
===============================================================
Employee Savings Plan
The Company sponsors a 401(k) defined contribution plan covering substantially
all employees. The Company provides a 75 percent matching contribution up to 6
percent of an employee's base salary. Total matching contributions made to the
plan for the years 2001, 2000, and 1999 were $16 million, $15 million, and $15
million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.
Retail Rate Orders
On December 20, 2001, the GPSC approved a new three-year retail rate order for
the Company ending December 31, 2004. Under the terms of the order, earnings
will be evaluated against a retail return on common equity range of 10 percent
to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will
be applied to rate refunds, with the remaining one-third retained by the
Company. Retail rates were decreased by $118 million effective January 1, 2002.
Under a previous three-year order ending December 2001, the Company's
earnings were evaluated against a retail return on common equity range of 10
percent to 12.5 percent. The order further provided for $85 million in each
year, plus up to $50 million of any earnings above the 12.5 percent return
during the second and third years, to be applied to accelerated amortization or
depreciation of assets. Two-thirds of any additional earnings above the 12.5
percent return were applied to rate refunds, with the remaining one-third
retained by the Company. Pursuant to the order, the Company recorded $336
million of accelerated amortization and interest thereon which has been credited
to a regulatory liability account as mandated by the GPSC.
Under the new rate order, the accelerated amortization and the interest will
be amortized equally over three years as a credit to expense beginning in 2002.
Effective January 1, 2002, the Company discontinued recording accelerated
II-105
NOTES (continued)
Georgia Power Company 2001 Annual Report
depreciation and amortization. The Company will not file for a general base rate
increase unless its projected retail return on common equity falls below 10
percent. Georgia Power is required to file a general rate case on July 1, 2004,
in response to which the GPSC would be expected to determine whether the rate
order should be continued, modified, or discontinued.
In 2000 and 1999, the Company recorded $44 million and $79 million,
respectively, of revenue subject to refund for estimated earnings above 12.5
percent retail return on common equity. Refunds applicable to 2000 and 1999 were
made to customers in 2001 and 2000, respectively.
Environmental Protection Agency (EPA) Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. 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
Bowen and Scherer plants. 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 Clean Air Act authorizes civil penalties of up to $27,500 per
day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.
The EPA concurrently issued a notice of violation to the Company relating
to these two plants. 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 case against the Company has been stayed since the spring of 2001
pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
appeal of a very similar Clean Air Act / New Source Review enforcement action
brought by EPA against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on Georgia Power, the Company is a party to that case as well. The
federal court in Georgia is currently considering a motion by the EPA to reopen
the Georgia case. The Company has opposed that motion. 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.
Other Environmental Contingencies
The Company has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act. Georgia
Power has recognized $33 million in cumulative expenses through December 31,
2001 for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia that is listed on the federal National Priorities List.
Georgia Power has contributed to the removal and remedial investigation and
feasibility study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated. As of December 31, 2001, Georgia
Power had recorded approximately $6 million in cumulative expenses associated
with Georgia Power's agreed-upon share of the removal and remedial investigation
and feasibility study costs for the Brunswick site.
The final outcome of these matters cannot now be determined. However, based
on the currently known conditions at these sites and the nature and extent of
Georgia Power's activities relating to these sites, management does not believe
that the Company's cumulative liability at these sites would be material to the
financial statements.
II-106
NOTES (continued)
Georgia Power Company 2001 Annual Report
Nuclear Performance Standards
The GPSC has adopted a nuclear performance standard for the Company's nuclear
generating units under which the performance of Plants Hatch and Vogtle is
evaluated every three years. The performance standard is based on each unit's
capacity factor as compared to the average of all comparable U.S. nuclear units
operating at a capacity factor of 50 percent or higher during the three-year
period of evaluation. Depending on the performance of the units, the Company
could receive a monetary award or penalty under the performance standards
criteria.
The GPSC has approved performance awards of approximately $11.7 million and
$7.8 million for performance during the 1993-1995 period and the 1996-1998
period, respectively. These awards are collected through the retail fuel cost
recovery provision and recognized in income over 36-month periods that began in
January 1997 and 2000, respectively, as mandated by the GPSC.
Race Discrimination Litigation
On July 28, 2000, a lawsuit alleging race discrimination was filed by three
Georgia Power employees against the Company, Southern Company, and SCS in the
United States District Court for the Northern District of Georgia. The lawsuit
also raised claims on behalf of a purported class. The plaintiffs seek
compensatory and punitive damages in an unspecified amount, as well as
injunctive relief. On August 14, 2000, the lawsuit was amended to add four more
plaintiffs. Also, an additional subsidiary of Southern Company, Southern Company
Energy Solutions, Inc., was named a defendant.
On October 11, 2001, the district court denied plaintiffs' motion for class
certification. The plaintiffs filed a motion to reconsider the order denying
class certification, and the court denied the plaintiffs' motion to reconsider.
On December 28, 2001, the plaintiffs filed a petition in the United States Court
of Appeals for the Eleventh Circuit seeking permission to file an appeal of the
October 11 decision. The defendants filed a brief in opposition of the petition
on January 18, 2002. Discovery of the seven named plaintiffs' individual claims
that remain in the case is ongoing. The final outcome of the case cannot be
determined.
4. COMMITMENTS
Construction Program
Georgia Power had three new generation projects under construction during 2001.
They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion
turbine facility; two combined cycle units totaling 1,132 megawatts at Plant
Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle
facility. All three of these projects have been transferred to Southern Power
Company, a new Southern Company affiliate formed in 2001 to construct, own, and
manage wholesale generating assets in the Southeast. The ten Dahlberg units and
two Goat Rock units were transferred in 2001 and the transfer of the two Wansley
units was completed in January 2002. Significant construction of transmission
and distribution facilities and projects to remain in compliance with
environmental requirements will continue. The Company currently estimates
property additions to be approximately $1.0 billion in 2002, $0.8 billion in
2003, and $0.8 billion in 2004.
In connection with the transfer of Plants Dahlberg, Goat Rock, and Wansley,
the Company has assigned $61 million in vendor equipment contracts to Southern
Power. While the Company could be obligated to assume responsibility for these
contracts if Southern Power fails to meet these commitments, Southern Company
has entered into limited keep-well arrangements whereby Southern Company would
contribute funds to Southern Power either through loans or capital
contributions in order to fund performance by Southern Power as equipment
purchaser under certain contingencies. Southern Company has also guaranteed
Southern Power obligations totaling $6.6 milion for the Company's construction
of transmission interconnection facilities to these plants.
The construction program is subject to periodic review and revision, and
actual construction costs may vary from estimates because of numerous factors,
including, but not limited to, changes in business conditions, load growth
estimates, environmental regulations, and regulatory requirements.
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.
II-107
NOTES (continued)
Georgia Power Company 2001 Annual Report
Total estimated long-term fossil and nuclear fuel commitments at December 31,
2001 were as follows:
Minimum
Year Obligations
- ---- -------------------
(in millions)
2002 $1,234
2003 1,115
2004 617
2005 527
2006 521
2007 and beyond 1,857
- -------------------------------------------------------------
Total $5,871
=============================================================
Additional commitments for coal and for nuclear fuel will be required in
the future to supply the Company's fuel needs.
In addition, SCS acts as agent for the five operating companies and
Southern Power with regard to natural gas purchases. Natural gas purchases (in
dollars) are based on various indices at the actual time of delivery; therefore,
only the volume commitments are firm and disclosed in the following chart. The
committed volumes, as of December 31, 2001 are as follows:
Year Natural Gas
- ---- ------------------
(MMBtu)
2002 18,927,055
2003 30,434,645
2004 30,352,580
2005 23,050,128
2006 20,038,214
2007 and beyond 7,153,129
- ---------------------------------------------------------------
Total 129,955,751
===============================================================
Purchased Power Commitments
The Company and an affiliate, Alabama Power, own equally all of the outstanding
capital stock of Southern Electric Generating Company (SEGCO), which owns
electric generating units with a total rated capacity of 1,020 megawatts, as
well as associated transmission facilities. The capacity of the units has been
sold equally to the Company and Alabama Power under a contract which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, debt service, and return on investment, 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 included in purchased power from
affiliates in the Statements of Income is as follows:
2001 2000 1999
---------------------------------
(in millions)
Energy $52 $57 $51
Capacity 30 30 29
- --------------------------------------------------------------
Total $82 $87 $80
==============================================================
The Company has commitments regarding a portion of a 5 percent interest in
Plant Vogtle owned by Municipal Electric Authority of Georgia (MEAG) that are in
effect until the latter of the retirement of the plant or the latest stated
maturity date of MEAG's bonds issued to finance such ownership interest. The
payments for capacity are required whether or not any capacity is available. The
energy cost is a function of each unit's variable operating costs. Except as
noted below, the cost of such capacity and energy is included in purchased power
from non-affiliates in the Company's Statements of Income. Capacity payments
totaled $59 million, $58 million, and $57 million in 2001, 2000, and 1999,
respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments
----------------------
(in millions)
2002 $ 58
2003 59
2004 55
2005 55
2006 55
2007 and beyond 483
- ----------------------------------------------------------------
Total $765
================================================================
Portions of the payments noted above relate to costs in excess of Plant
Vogtle's allowed investment for ratemaking purposes. The present value of these
portions was written off in 1987 and 1990.
II-108
NOTES (continued)
Georgia Power Company 2001 Annual Report
The Company has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
2001 were as follows:
Year Non-
Affiliated Affiliated
- ---- --------------------------------
(in millions)
2002 $ 66 $ 39
2003 123 41
2004 183 40
2005 198 40
2006 197 40
2007 and beyond 1,138 396
- ------------------------------------------------------------
Total $1,905 $596
============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $14 million for 2001, $16 million
for 2000, and $11 million for 1999. At December 31, 2001, estimated minimum
rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations
-----------------------
(in millions)
2002 $ 15
2003 15
2004 15
2005 15
2006 15
2007 and beyond 91
- --------------------------------------------------------------
Total $166
==============================================================
In addition to the rental commitments above, the Company has obligations upon
expiration of certain of the rail car leases with respect to the residual value
of the leased property. These leases expire in 2004 and 2010, and the Company's
maximum obligations are $13 million and $40 million, respectively. At the
termination of the leases, at the Company's option, the Company may either
exercise its purchase option or the property can be sold to a third party. The
Company expects that the fair market value of the leased property would
substantially reduce or eliminate the Company's payments under the residual
value obligation.
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, 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 the
Company's nuclear power plants. The Act provides funds up to $9.5 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $200 million by
American Nuclear Insurers (ANI), with the remaining coverage provided by a
mandatory program of deferred premiums that 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 for the Company, excluding any
applicable state premium taxes -- based on its ownership and buyback interests
- -- is $178 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 costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years.
Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $39 million.
II-109
NOTES (continued)
Georgia Power Company 2001 Annual Report
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies should 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.
6. JOINT OWNERSHIP AGREEMENTS
Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned generating facilities. The Company jointly owns the Rocky
Mountain pumped storage hydroelectric plant with Oglethorpe Power Company who is
the operator of the plant. The Company also jointly owns Plant McIntosh with
Savannah Electric and Power Company who operates the plant. The Company and
Florida Power Corporation (FPC) jointly own a combustion turbine unit
(Intercession City) operated by FPC.
The Company includes its proportionate share of plant operating expenses in
the corresponding operating expenses in the Statements of Income.
At December 31, 2001, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial operation
were as follows:
Company Accumulated
Facility (Type) Ownership Investment Depreciation
- --------------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) 45.7% $3,304 $1,793
Plant Hatch (nuclear) 50.1 881 668
Plant Wansley (coal) 53.5 309 152
Plant Scherer (coal)
Units 1 and 2 8.4 112 56
Unit 3 75.0 545 221
Plant McIntosh
Common Facilities 75.0 24 2
(combustion-turbine)
Rocky Mountain 25.4 169 78
(pumped storage)
Intercession City 33.3 12 1
(combustion-turbine)
- --------------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating companies of Southern Company have 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 consist of firm unit power sales pertaining to capacity from specific
generating units. Because energy is generally sold at cost under these
agreements, it is primarily the capacity revenues that affect the Company's
profitability.
The Company's capacity revenues were as follows:
Year Revenues Capacity
----------------------------------
(in millions) (megawatts)
2001 $ 26 102
2000 30 124
1999 32 162
----------------------------------
Unit power from specific generating plants is being sold to Florida Power &
Light Company, FPC, and Jacksonville Electric Authority. Under these agreements,
approximately 102 megawatts of capacity is scheduled to be sold annually for
periods after 2001 with a minimum of three years notice until the expiration of
the contracts in 2010.
8. INCOME TAXES
At December 31, 2001, tax-related regulatory assets were $544 million and
tax-related regulatory liabilities were $229 million. The assets are
II-110
NOTES (continued)
Georgia Power Company 2001 Annual Report
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized interest. The 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 federal and state income tax provisions are as follows:
2001 2000 1999
----------------------------
Total provision for income taxes: (in millions)
Federal:
Current $352 $342 $333
Deferred (46) (34) (34)
- --------------------------------------------------------------
306 308 299
- --------------------------------------------------------------
State:
Current 61 48 54
Deferred (8) (5) (6)
Deferred investment tax
credits 5 10 5
- --------------------------------------------------------------
Total $364 $361 $352
==============================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
2001 2000
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,722 $1,755
Property basis differences 660 683
Other 295 243
- -----------------------------------------------------------------
Total 2,677 2,681
- -----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 178 189
Federal effect of state deferred taxes 88 91
Other deferred costs 257 208
Other 40 37
- -----------------------------------------------------------------
Total 563 525
- -----------------------------------------------------------------
Net deferred tax liabilities 2,114 2,156
Portion included in current assets 50 27
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,164 $2,183
=================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $15 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
2001 2000 1999
-------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 2 2
Other (4) (2) (2)
- --------------------------------------------------------------
Effective income tax rate 37% 39% 39%
==============================================================
Southern Company and its subsidiaries file 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. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.
9. CAPITALIZATION
First Mortgage Bond Indenture Restrictions
The Company's first mortgage bond indenture contains various restrictions that
remain in effect as long as the bonds are outstanding. However, the Company
expects to discharge its first mortgage bond indenture by spring 2002 and to be
released from all indenture requirements. At December 31, 2001, $1.037 billion
of retained earnings and paid-in capital was unrestricted for the payment of
cash dividends or any other distributions under terms of the mortgage indenture.
The Company has no restrictions on the amount of indebtedness it may incur.
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 8/1996 $225.00 7.75% $232 6/2036
Trust II 1/1997 175.00 7.60 180 12/2036
Trust III 6/1997 189.25 7.75 195 3/2037
Trust IV 2/1999 200.00 6.85 206 3/2029
II-111
NOTES (continued)
Georgia Power Company 2001 Annual Report
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.
The Trusts are subsidiaries of the Company, and accordingly are
consolidated in the Company's financial statements.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The Company has
authenticated and delivered to trustees an aggregate of $7.8 million of its
first mortgage bonds outstanding at December 31, 2001, which are pledged as
security for its obligations under pollution control revenue contracts. The
redemption of these securities will occur in March 2002.
Senior Notes
In February 2000, February 2001, and May 2001, the Company issued unsecured
senior notes. The proceeds of these issues were used to redeem higher cost
long-term debt and to reduce short-term borrowing. The senior notes are, in
effect, subordinated to all secured debt of the Company.
Bank Credit Arrangements
At the beginning of 2002, the Company had unused credit arrangements with banks
totaling $1.8 billion, of which $1.3 billion expires at various times during
2002 and $500 million expires at April 24, 2003.
Of the total $1.8 billion in unused credit, $1.65 billion is a syndicated
credit arrangement with $1.15 billion expiring April 19, 2002 and $500 million
expiring April 24, 2003. Upon expiration, the $1.15 billion agreement provides
the option of converting borrowings into two-year term loans. Both agreements
contain stated borrowing rates but also allow for competitive bid loans. In
addition, the agreements require payment of commitment fees based on the unused
portions of the commitments. Annual fees are also paid to the agent bank.
Approximately $115 million of the $1.3 billion arrangements expiring during
2002 allow for two-year term loans executable upon the expiration date of the
facilities. All of the arrangements include stated borrowing rates but also
allow for negotiated rates. These agreements also require payment of commitment
fees based on the unused portion of the commitments or the maintenance of
compensating balances with the banks. These balances are not legally restricted
from withdrawal.
This $1.8 billion in unused credit arrangements provides liquidity support
to the Company's variable rate pollution control bonds. The amount of variable
rate pollution control bonds outstanding requiring that liquidity support as of
December 31, 2001 was $984 million.
In addition, the Company borrows under uncommitted lines of credit with
banks and through commercial paper programs that has the liquidity support of
committed bank credit arrangements. Average compensating balances held under
these committed facilities were not material in 2001. The amount of commercial
paper outstanding at December 31, 2001 was $707.6 million
Other Long-Term Debt
Assets acquired under capital leases are recorded in the Balance Sheets as
utility plant in service, and the related obligations are classified as
long-term debt. At December 31, 2001 and 2000, the Company had a capitalized
lease obligation for its corporate headquarters building of $83 million with an
interest rate of 8.1 percent. For ratemaking purposes, the GPSC has treated the
lease as an operating lease and has allowed only the lease payments in cost of
service. The difference between the accrued expense and the lease payments
allowed for ratemaking purposes has been deferred and is being amortized to
expense as ordered by the GPSC. At December 31, 2001 and 2000, the interest and
lease amortization deferred on the Balance Sheets are $54 million and $55
million, respectively.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, 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.
II-112
NOTES (continued)
Georgia Power Company 2001 Annual Report
Georgia Power expects to discharge its first mortgage bond indenture by spring
2002 and that the lien will be removed.
Securities Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of securities due within one year at December 31 is as follows:
2001 2000
------------------
(in millions)
Capital lease $ 2 $2
First mortgage bonds 2 -
Pollution control bonds 8 -
Senior notes 300 -
- ---------------------------------------------------------------
Total $312 $2
===============================================================
The Company's first mortgage bond indenture includes an improvement fund
requirement that amounts to 1 percent of each outstanding series of bonds
authenticated under the indenture prior to January 1 of each year, other than
those issued to collateralize pollution control obligations. The requirement may
be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. However, the
Company expects to discharge its first mortgage bond indenture by spring 2002
and to be released from all indenture requirements.
Serial maturities through 2006 applicable to total long-term debt are as
follows: $312 million in 2002; $352 million in 2003; $2 million in 2004; $154
million in 2005; and $153 million in 2006.
10. QUARTERLY FINANCIAL DATA
(UNAUDITED)
Summarized quarterly financial information for 2001 and 2000 is as follows:
Net Income
After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 2001 $1,108 $249 $108
June 2001 1,259 322 163
September 2001 1,579 515 298
December 2001 1,020 126 41
March 2000 $ 992 $223 $ 94
June 2000 1,221 311 148
September 2000 1,545 537 283
December 2000 1,113 162 34
- ---------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-113
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Georgia Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,965,794 $4,870,618 $4,456,675 $4,738,253 $4,385,717
Net Income after Dividends
on Preferred Stock (in thousands) $610,335 $559,420 $541,383 $570,228 $593,996
Cash Dividends
on Common Stock (in thousands) $527,300 $549,600 $543,000 $536,600 $520,000
Return on Average Common Equity (percent) 14.12 13.66 14.02 14.61 14.53
Total Assets (in thousands) $13,565,941 $13,075,767 $12,361,860 $12,033,618 $12,573,728
Gross Property Additions (in thousands) $1,389,751 $1,078,163 $790,464 $499,053 $475,921
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,397,485 $4,249,544 $3,938,210 $3,784,172 $4,019,728
Preferred stock 14,569 14,569 14,952 15,527 157,247
Company obligated mandatorily
redeemable preferred securities 789,250 789,250 789,250 689,250 689,250
Long-term debt 2,961,726 3,041,939 2,688,358 2,744,362 2,982,835
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,163,030 $8,095,302 $7,430,770 $7,233,311 $7,849,060
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 53.9 52.5 53.0 52.3 51.2
Preferred stock 0.2 0.2 0.2 0.2 2.0
Company obligated mandatorily
redeemable preferred securities 9.6 9.7 10.6 9.5 8.8
Long-term debt 36.3 37.6 36.2 38.0 38.0
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's A A A+ A+ A+
Fitch AA- AA- AA- AA- AA-
Preferred Stock -
Moody's Baa1 a2 a2 a2 a2
Standard and Poor's BBB+ BBB+ A- A A
Fitch A A A+ A+ A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 A2
Standard and Poor's A A A A A
Fitch A+ A+ A+ A+ A+
================================================================================================================================
Customers (year-end):
Residential 1,698,407 1,669,566 1,632,450 1,596,488 1,561,675
Commercial 244,674 237,977 229,524 221,180 211,672
Industrial 8,046 8,533 8,958 9,485 9,988
Other 3,239 3,159 3,060 3,034 2,748
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,954,366 1,919,235 1,873,992 1,830,187 1,786,083
================================================================================================================================
Employees (year-end): 9,048 8,860 8,961 8,371 8,354
- --------------------------------------------------------------------------------------------------------------------------------
II-114
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Georgia Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,507,031 $1,535,684 $ 1,410,099 $ 1,486,699 $ 1,326,787
Commercial 1,682,918 1,620,466 1,527,880 1,591,363 1,493,353
Industrial 1,106,420 1,154,789 1,143,001 1,170,881 1,110,311
Other 52,943 6,399 (30,892) 49,274 47,848
- ----------------------------------------------------------------------------------------------------------------------------
Total retail 4,349,312 4,317,338 4,050,088 4,298,217 3,978,299
Sales for resale - non-affiliates 366,085 297,643 210,104 259,234 282,365
Sales for resale - affiliates 99,411 96,150 76,426 81,606 38,708
- ----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,814,808 4,711,131 4,336,618 4,639,057 4,299,372
Other revenues 150,986 159,487 120,057 99,196 86,345
- ----------------------------------------------------------------------------------------------------------------------------
Total $4,965,794 $4,870,618 $4,456,675 $4,738,253 $4,385,717
============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 20,119,080 20,693,481 19,404,709 19,481,486 17,295,022
Commercial 26,493,255 25,628,402 23,715,485 22,861,391 21,134,346
Industrial 25,349,477 27,543,265 27,300,355 27,283,147 26,701,685
Other 583,007 568,906 551,451 543,462 538,163
- ----------------------------------------------------------------------------------------------------------------------------
Total retail 72,544,819 74,434,054 70,972,000 70,169,486 65,669,216
Sales for resale - non-affiliates 8,110,096 6,463,723 5,060,931 6,438,891 6,795,300
Sales for resale - affiliates 3,133,485 2,435,106 1,795,243 2,038,400 1,706,699
- ----------------------------------------------------------------------------------------------------------------------------
Total 83,788,400 83,332,883 77,828,174 78,646,777 74,171,215
============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.49 7.42 7.27 7.63 7.67
Commercial 6.35 6.32 6.44 6.96 7.07
Industrial 4.36 4.19 4.19 4.29 4.16
Total retail 6.00 5.80 5.71 6.13 6.06
Sales for resale 4.14 4.43 4.18 4.02 3.78
Total sales 5.75 5.65 5.57 5.90 5.80
Residential Average Annual
Kilowatt-Hour Use Per Customer 11,933 12,520 12,006 12,314 11,171
Residential Average Annual
Revenue Per Customer $893.84 $929.11 $872.48 $939.73 $857.01
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 14,474 15,114 14,474 14,437 14,437
Maximum Peak-Hour Demand (megawatts):
Winter 11,977 12,014 11,568 11,959 10,407
Summer 14,294 14,930 14,575 13,923 13,153
Annual Load Factor (percent) 61.7 61.6 58.9 58.7 57.4
Plant Availability (percent):
Fossil-steam 88.5 86.1 84.3 86.0 85.8
Nuclear 94.4 91.5 89.3 91.6 88.8
- ----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 58.5 62.3 63.0 62.3 64.3
Nuclear 18.1 17.4 18.0 18.3 18.8
Hydro 1.1 0.7 0.9 2.2 2.2
Oil and gas 0.4 1.8 1.6 2.2 0.6
Purchased power -
From non-affiliates 7.8 8.1 6.6 6.5 2.7
From affiliates 14.1 9.7 9.9 8.5 11.4
- ----------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
============================================================================================================================
II-115
GULF POWER COMPANY
FINANCIAL SECTION
II-116
MANAGEMENT'S REPORT
Gulf Power Company 2001 Annual Report
The management of Gulf Power Company has prepared -- and is responsible for --
the financial statements and related information included in this report. These
statements were prepared in accordance with accounting principles generally
accepted in the United States and necessarily include amounts that are based on
the best estimates and judgments of management. Financial information throughout
this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of five independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Gulf Power Company in conformity with accounting principles generally
accepted in the United States.
/s/ Travis J. Bowden
Travis J. Bowden
President
and Chief Executive Officer
/s/Ronnie R. Labrato
Ronnie R. Labrato
Vice President, Chief Financial Officer
and Comptroller
February 13, 2002
II-117
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Gulf Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Gulf Power Company (a Maine corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 2001 and 2000, and the related statements
of income, common stockholder's equity, and cash flows for each of the three
years in the period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements (pages II-129 through II-144)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Gulf Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-118
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 2001 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 2001 net income after dividends on preferred stock was
$58.3 million, an increase of $6.5 million from the previous year. In 2000,
earnings were $51.8 million, down $1.9 million when compared to 1999. The
increase in earnings in 2001 was due primarily to an increase in Allowance for
Funds Used During Construction (AFUDC) and lower interest expense; the decrease
in 2000 was primarily a result of expenses related to the discontinuance of the
Company's appliance sales division, and higher interest expense.
Revenues
Operating revenues increased in 2001 when compared to 2000. The following table
summarizes the change in operating revenues for the past two years:
Increase (Decrease)
Amount From Prior Year
------------------------------------
2001 2001 2000
------------------------------------
(in thousands)
Retail --
Base Revenues $340,620 $4,517 $3,771
Regulatory cost
recovery and other 243,971 31,434 27,920
- -----------------------------------------------------------------
Total retail 584,591 35,951 31,691
- ------------------------------------------------------ ----------
Sales for resale--
Non-affiliates 82,252 15,362 4,536
Affiliates 27,256 (39,739) 885
- -----------------------------------------------------------------
Total sales for resale 109,508 (24,377) 5,421
Other operating
revenues 31,104 (690) 3,108
- -----------------------------------------------------------------
Total operating
revenues $725,203 $10,884 $40,220
=================================================================
Percent change 1.5% 6.0%
- ----------------------------------------------------------------
Retail revenues increased $36 million, or 6.6 percent in 2001, and $31.7
million or 6.1 percent in 2000, due primarily to the recovery of higher fuel and
purchased power costs. Retail base rate revenues increased $4.5 million due to
slightly higher energy sales and lower revenues subject to refund. Revenues
subject to refund were $1.5 million in 2001 compared to $6.9 million in 2000.
See Note 3 to the financial statements under "Retail Revenue Sharing Plan" for
further information.
"Regulatory cost recovery and other" includes: recovery provisions for fuel
expenses and the energy component of purchased power costs, energy conservation
costs, purchased power capacity costs, and environmental compliance costs.
Annually, the Company seeks recovery of projected costs plus any true-up amount
from prior periods. Approved rates are implemented each January. Therefore, the
recovery provisions generally equal the related expenses and have no material
effect on net income. See Notes 1 and 3 to the financial statements under
"Revenues and Regulatory Cost Recovery Clauses" and "Environmental Cost
Recovery," respectively, for further information.
Sales for resale were $109.5 million in 2001, a decrease of $24.4 million, or
18.2 percent, from 2000 primarily due to reduced energy sales for resale to
affiliates. Revenues from sales to utilities outside the service area under
long-term contracts consist of capacity and energy components. Capacity revenues
reflect the recovery of fixed costs and a return on investment under the
contracts. Energy is generally sold at variable cost. The capacity and energy
components under these long-term contracts were as follows:
2001 2000 1999
----------------------------------------
(in thousands)
Capacity $19,472 $20,270 $19,792
Energy 27,579 21,922 20,251
- -------------------------------------------------------------
Total $47,051 $42,192 $40,043
=============================================================
Capacity revenues remained relatively unchanged during 2001 and 2000.
Sales to affiliated companies vary from year to year depending on demand and
the availability and cost of generating resources at each company. These sales
have little impact on earnings.
Other operating revenues for 2000 increased due primarily to higher franchise
fees and higher revenues from the transmission of electricity to others.
II-119
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
Energy Sales
Kilowatt-hour sales for 2001 and the percent changes by year were as follows:
KWH Percent Change
--------------------------------
2001 2001 2000
--------------------------------
(millions)
Residential 4,716 (1.5)% 7.1%
Commercial 3,418 1.2 4.9
Industrial 2,018 4.8 4.3
Other 21 10.5 0.0
-------------
Total retail 10,173 0.6 5.8
Sales for resale
Non-affiliates 2,093 22.8 9.2
Affiliates 963 (49.8) (23.7)
-------------
Total 13,229 (3.7) 0.7
=====================================================
Total retail energy sales increased in both 2001 and 2000 primarily due to an
increase in the total number of customers.
An increase in energy sales for resale to non-affiliates of 22.8 percent in
2001 when compared to 2000 is primarily related to unit power sales under
long-term contracts to other Florida utilities and bulk power sales under
short-term contracts to other non-affiliated utilities. Energy sales to
affiliated companies vary from year to year depending on demand and availability
and cost of generating resources at each company.
Expenses
Total operating expenses in 2001 increased $13.5 million, or 2.3 percent, over
the amount recorded in 2000 due primarily to higher purchased power expenses and
maintenance expenses. In 2000, total operating expenses increased $39.5 million,
or 7.1 percent, compared to 1999 due primarily to higher fuel and purchased
power expenses.
Fuel expenses in 2001, when compared to 2000, decreased $15.1 million, or 7.0
percent, due primarily to decreased generation, while average fuel costs
increased as noted below. In 2000, fuel expenses increased $6.7 million, or 3.2
percent, when compared to 1999. The increase in 2000 was a result of an increase
in average fuel costs.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
2001 2000 1999
-------------------------------
Total generation
(millions of kilowatt-hours) 11,423 12,866 13,095
Sources of generation
(percent)
Coal 99.0 98.2 97.4
Oil and gas 1.0 1.8 2.6
Average cost of fuel per net
kilowatt-hour generated
(cents)-- 1.76 1.68 1.60
- ---------------------------------------------------------------------
Purchased power expenses increased in 2001 by $23.8 million, or 28.8 percent,
over 2000 primarily due to an increase in purchased power from affiliate
companies. Purchased power expenses for 2000 increased over 1999 by $25.5
million, or 44.7 percent, due primarily to a higher demand for energy.
Purchases of energy from affiliates will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These purchases have little impact on earnings.
Depreciation and amortization expense increased $1.3 million, or 2.0 percent,
in 2001, and $2.3 million, or 3.5 percent, in 2000 due to an increase in
depreciable property and the amortization of a portion of a regulatory asset,
which was allowed in the current retail revenue sharing plan.
Other income, net increased in 2001 by $6.8 million compared to 2000 due
primarily to higher allowance for equity funds used during construction related
to the Company's new combined cycle unit. In 2000, other income, net decreased
$2.8 million due primarily to expenses related to the discontinuance of the
Company's appliance sales division. See Note 1 to the financial statements under
"Other Income" for further information.
Interest expense, net decreased $3.1 million, or 10.9 percent, in 2001 due
primarily to higher allowance for debt funds used during construction related to
the Company's new combined cycle unit, as well as lower interest rates on notes
payable and variable rate pollution control bonds. These decreases were
partially offset by the issuance of $60 million of senior notes in August 2001
and $75 million of senior notes in October 2001. In 2000, interest expense, net
II-120
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
increased $1.2 million, or 4.6 percent, due primarily to the issuance of $50
million of senior notes in August 1999.
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 cost of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
General
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors. The major factor is the ability to achieve energy sales growth
while containing costs in a more competitive environment.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash income of
approximately $5.9 million in 2001. Future pension income is dependent on
several factors including trust earnings and changes to the plan.
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.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
northwest Florida. Prices for electricity provided by the Company to retail
customers are set by the Florida Public Service Commission (FPSC).
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 the rate of economic growth in the Company's service area, weather,
competition, changes in contracts with neighboring utilities, the elasticity of
demand, and energy conservation practiced by the Company's customers. The
Company is actively pursuing additional earnings through unregulated new
products and services.
In early 1999, the FPSC staff and the Company became involved in discussions
primarily related to reducing the Company's authorized rate of return. On
October 1, 1999, the Office of Public Counsel, the Coalition for Equitable
Rates, the Florida Industrial Power Users Group, and the Company jointly filed a
petition to resolve the issues. The stipulation included a reduction to retail
base rates of $10 million annually and provides for revenues to be shared within
set ranges for 1999 through 2002. Customers receive two-thirds of any revenue
within the sharing range and the Company retains one-third. Any revenue above
this range is refunded to the customers. The stipulation also included
authorization for the Company, at its discretion, to accrue up to an additional
$5 million to the property insurance reserve and $1 million to amortize a
regulatory asset related to the corporate office. The Company also filed a
request to prospectively reduce its authorized return on equity (ROE) range from
11 to 13 percent to 10.5 to 12.5 percent in order to help ensure that the FPSC
would approve the stipulation. The FPSC approved both the stipulation and the
ROE request with an effective date of November 4, 1999.
On September 10, 2001, the Company filed a request with the FPSC for a base
rate increase of approximately $70 million, the majority of which is needed to
recover costs related to the Smith Unit 3 combined cycle facility currently
under construction and scheduled to be placed in service by June 2002. Hearings
are scheduled for February 25 through March 1, 2002 with a decision expected in
early May 2002 and new rates effective June 6, 2002.
For calendar year 2001, the Company's retail revenue range for sharing was
$358 million to $374 million. Actual retail revenues in 2001 were $360.3 million
and the Company recorded revenues subject to refund of $1.5 million. The
estimated refund with interest was reflected in customer billings in February
2002. For calendar year 2002, there are specified sharing ranges for each month
from the expected in-service date of Smith Unit 3 until the end of the year. The
II-121
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
sharing plan will expire at the earlier of the in-service date of Smith Unit 3
or December 31, 2002.
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." Also, Florida legislation adopted in 1993 that provides
for recovery of prudent environmental compliance costs is discussed in Note 3 to
the financial statements under "Environmental Cost Recovery."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as
a result of regulatory and competitive factors. Among the primary agents of
change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act
allows independent power producers (IPPs) to access a utility's transmission
network in order to sell electricity to other utilities. This enhances the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and commercial customers and sell 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.
Although the Energy Act does not permit retail customer access, it has been a
major catalyst for recent restructuring and consolidations taking place within
the utility industry. Numerous federal and state initiatives are in varying
stages to promote wholesale and retail competition. Among other things, these
initiatives allow customers to choose their electricity provider. Some states
have approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While various restructuring and
competition initiatives have been discussed in Florida, none have been enacted.
Enactment would require numerous issues to be resolved, including significant
ones relating to recovery of any stranded investments, full cost recovery of
energy produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation.
In 2000, Florida's Governor appointed a 17 member study commission to look at
the state's electric industry, studying issues ranging from current and future
reliability of electric and natural gas supply, electric industry retail and
wholesale competition, environmental impacts of energy supply, conservation, and
tax issues. A deadline of December 1, 2001 was set for the commission's final
report and recommendations to the Governor and the Legislature. During the
course of the study, the Stranded Investment Task Force Subcommittee recommended
a discretionary transfer approach regarding the transfer or sale of generation
assets by an investor owned utility (IOU). This would allow all new generation
to be competitively bid while allowing IOU's to transfer generation units to an
affiliate or sell generation units and share proceeds with both shareholders and
consumers. Merchants would also be allowed to compete in this restructured
wholesale market. This recommendation was approved during the final meeting of
the study commission on November 15, 2001 and has been incorporated into the
final report. The final report, entitled "Florida...Energy Wise" was presented
on December 11, 2001 to the Governor and the Legislature. Any recommendations
from the commission will have to be drafted and voted into law by the
Legislature. This is unlikely to occur in the upcoming 2002 legislative session.
The effects of any proposed changes cannot presently be determined, but could
have a material effect on the Company's 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.
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
Southern Company explained that it is developing a for profit RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
II-122
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the SeTrans RTO. Southern Company continues to work with the
other sponsors to develop the SeTrans RTO. The creation of SeTrans is not
expected to have a material impact on the Company's financial statements. The
outcome of this matter cannot now be determined.
Accounting Policies
Critical Policy
Gulf Power Company's significant accounting policies are described in Note 1 to
the financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's 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 Standards
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. The
impact on net income in 2001 was not material. (See Note 1 to the financial
statements under "Financial Instruments" for additional information). An
additional interpretation of Statement No. 133 will result in a change --
effective April 1, 2002 -- in accounting for certain contracts related to fuel
supplies that contain quantity options. These contracts will be accounted for as
derivatives and marked to market. However, due to the existence of specific
cost-based fuel recovery clauses for the Company, this change is not expected to
have a material impact on net income.
In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No. 142 in January 2002 with no material
impact on the financial statements.
Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.
FINANCIAL CONDITION
Overview
During 2001, gross property additions were $274.7 million. Funds for the
Company's property additions were provided by operating activities and
additional financings, which were utilized to finance the construction of the
Company's new combined cycle unit. See the Statements of Cash Flows for further
details.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.
II-123
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
Exposure to Market Risks
Due to cost-based rate regulations, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market and, to a lesser extent,
similar contracts for gas purchases. Realized gains and losses are recognized in
the income statement as incurred. At December 31, 2001, exposure from these
activities was not material. Fair value of changes in energy trading contracts
and year-end valuations are as follows:
Changes During the Year
- ----------------------------------------------------------------
Fair Value
- ----------------------------------------------------------------
(in thousands)
Contracts beginning of year $110
Contracts realized or settled (100)
New contracts at inception -
Changes in valuation techniques -
Current period changes (120)
- ----------------------------------------------------------------
Contracts end of year $(110)
================================================================
Source of Year-End Valuation Prices
- ----------------------------------------------------------------
Maturity
Total ---------
Fair Value Year 1 1-3 Years
- ----------------------------------------------------------------
(in thousands)
Actively quoted $(110) $(102) $(8)
External sources - - -
Models and other
methods - - -
- ----------------------------------------------------------------
Contracts end of year $(110) $(102) $(8)
================================================================
If the Company sustained a 100 basis point change in interest rates for all
variable rate long-term debt, the change would affect annualized interest
expense by approximately $0.61 million at December 31, 2001.
Financing Activities
In 2001, the Company sold $135 million of senior notes and $30 million of trust
preferred securities and used the proceeds to retire $30 million of first
mortgage bonds and to pay for construction of the Company's new combined cycle
unit. In 2000, there were no issuances or retirements of long-term debt. See the
Statements of Cash Flows for further details.
Composite financing rates for the years 1999 through 2001 as of year end were
as follows:
2001 2000 1999
-----------------------------
Composite interest rate on
long-term debt 5.6% 6.2% 6.0%
Composite rate on
trust preferred securities 7.2% 7.3% 7.3%
Composite preferred stock
dividend rate 5.1% 5.1% 5.1%
- -----------------------------------------------------------------
The composite interest rate on long-term debt decreased in 2001 due to lower
interest rates on variable rate pollution control bonds and lower rates on new
senior notes.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $282 million for the three years
beginning in 2002 ($103 million in 2002, $72 million in 2003, and $107 million
in 2004). These amounts include $24.3 million in 2002 for the remaining cost of
a 574 megawatt combined cycle gas generating unit and related interconnections
to be located in the eastern portion of the Company's service area. The unit is
expected to have an in-service date of June 2002. The remaining property
additions budget is primarily for maintaining and upgrading transmission and
distribution facilities and generating plants. Actual construction costs may
vary from this estimate because of changes in such factors as the following:
business conditions; environmental 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
The Company will continue to retire higher-cost debt and preferred securities
and replace these securities with lower-cost capital as market conditions and
terms of the instruments permit.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
Future note maturities, operating lease obligations, and purchase
commitments - discussed in notes 4 and 8 to the financial statements --
are as follows:
2002 2003 2004
- --------------------------------------------------------------
(in millions)
Bonds -
First mortgage $ - $ - $ -
Pollution control - - -
Notes - 61 51
Leases -
Capital - - -
Operating 2 2 2
- --------------------------------------------------------------
Purchase commitments
Fuel 140 109 112
Purchased power 2 1 1
- --------------------------------------------------------------
At the beginning of 2002, the Company had not used any of its available
credit arrangements. Credit arrangements are as follows:
Expires
-----------------------------
Total Unused 2002 2003 & beyond
- --------------------------------------------------------------
(in millions)
$103 $103 $103 $ -
- --------------------------------------------------------------
Environmental Matters
In November 1990, the Clean Air Act Amendments of 1990 (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 Company. Specific reductions
in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating
plants were required in two phases. Phase I compliance began in 1995. Southern
Company achieved Phase I compliance at the affected plants by primarily
switching to low-sulfur coal and with some equipment upgrades. Construction
expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance
totaled approximately $42 million for the Company. Phase II sulfur dioxide
compliance was required in 2000. Southern Company used emission allowances and
fuel switching to comply with Phase II requirements. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits and ozone non-attainment requirements for
metropolitan Atlanta through 2000. Phase II compliance did not have a material
impact on the Company.
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
In 1993, the Florida Legislature adopted legislation that allows a utility to
petition the FPSC for recovery of prudent environmental compliance costs that
are not being recovered through base rates or any other recovery mechanism. The
legislation is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery." Substantially all of the costs for the Clean Air
Act and other new environmental legislation discussed below are expected to be
recovered through the Environmental Cost Recovery Clause.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
made the standards significantly more stringent. In the subsequent litigation of
these standards, the U.S. Supreme Court found the EPA's implementation program
for the new ozone standard unlawful and remanded it to the EPA. In addition, the
Federal District of Columbia Circuit Court of Appeals is considering other legal
challenges to these standards. If the standards are eventually upheld,
implementation could be required by 2007 to 2010.
In September 1998, the EPA issued regional nitrogen oxide reduction rule to
the states for implementation. Compliance is required by May 31, 2004 for most
states, but for Georgia, further ratemaking is required and compliance may be
delayed until May 2005. The final rule affects 21 states, including Georgia, but
not Florida. See Note 5 to the financial statements under "Joint Ownership
Agreements" related to the Company's ownership interest in Georgia Power's Plant
Scherer Unit No. 3. The EPA is presently evaluating whether to bring an
additional 15 states, not including Florida, under this regional nitrogen oxide
rule.
In December 2000, the EPA completed its utility study for mercury and other
hazardous air pollutants (HAPS) and issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is to be developed over the next four years under the Maximum Achievable Control
Technology provisions of the Clean Air Act, and the regulations are scheduled to
be finalized by the end of 2004 with implementation to take place around 2007.
In January 2001, the EPA proposed guidance for the determination of Best
II-125
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
Available Retrofit Technology (BART) emission controls under the Regional Haze
Regulations. Installation of BART controls is expected to take place around
2010. Litigation of the Regional Haze Regulations, including the BART
provisions, is ongoing in the Federal District of Columbia Circuit Court of
Appeals. A court decision is expected in mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by EPA in March 2001 in response to a
court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.
The EPA and state environmental regulatory agencies are also reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
On November 3, 1999, the EPA brought a civil action in the U.S. District
Court against Alabama Power, Georgia Power, and the system service company. The
complaint alleges violations of the prevention of significant deterioration and
new source review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. For additional
information, see Note 5 to the financial statements under "Joint Ownership
Agreements" related to the Company's ownership interest in Georgia Power's Plant
Scherer Unit No. 3. In early 2000, the EPA filed a motion to amend its complaint
to add the violations alleged in its notice of violation, and to add the
Company, Mississippi Power, and Savannah Electric as defendants. The complaint
and notice of violation are similar to those brought against and issued to
several other electric utilities. These complaints and notices of violation
allege that the utilities had failed to secure necessary permits or install
additional pollution control equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. The U.S. District Court granted Alabama Power's motion to dismiss for lack
of jurisdiction in Georgia and granted the system service company's motion to
dismiss on the grounds that it neither owned nor operated the generating units
involved in the proceedings. The court directed the EPA to re-file its amended
complaint limiting claims to those brought against Georgia Power and Savannah
Electric. The EPA re-filed those claims as directed by the court. Also, the EPA
re-filed its claims against Alabama Power in U.S. District Court in Alabama. It
has not re-filed against the Company, Mississippi Power, or the system service
company. The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.
The Company believes that it has 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
II-126
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
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.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup
costs and has recognized in the financial statements costs to clean up known
sites. For additional information, see Note 3 to the financial statements under
"Environmental Cost Recovery."
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electric and magnetic fields, and other environmental health concerns
could significantly affect the Company. The impact of new legislation -- if any
- -- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electric and magnetic fields.
Sources of Capital
At December 31, 2001, the Company had approximately $2.2 million of cash and
cash equivalents and $2.6 million of unused commercial paper backed by lines of
credit with banks to meet its short-term cash needs. See the Statements of Cash
Flows for details related to the Company's financing activities. See Note 8 to
the financial statements under "Bank Credit Arrangements" for additional
information.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $37.4 million of commercial
paper.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control 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, in order to issue first mortgage
bonds or preferred stock, the Company is required to meet certain coverage
requirements specified in its mortgage indenture and corporate charter. The
Company's ability to satisfy all coverage requirements is such that it could
issue new first mortgage bonds and preferred stock to provide sufficient funds
for all anticipated requirements.
Cautionary Statement Regarding Forward-Looking Information
The Company's 2001 Annual Report contains forward looking and historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "could," "should," "expects," "plans,"
"anticipates," "believes," "estimates," "projects," "predicts," "potential" or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action; the effects, extent, and timing of the entry of additional competition
in the markets of the Company; the impact of fluctuations in commodity prices,
interest rates and customer demand; state and federal rate regulations;
political, legal, and economic conditions and developments in the United States;
the performance of projects undertaken by the non-traditional business and the
success of efforts to invest in and develop new opportunities; internal
II-127
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2001 Annual Report
restructuring or other restructuring options that may be pursued; potential
business strategies, including acquisitions or dispositions of assets or
businesses, which cannot be assured to be completed or beneficial to the Company
the effects of, and changes in, economic conditions in the Company's service
territory; the direct or indirect effects on the Company's business resulting
from the terrorist incident on September 11, 2001, or any similar such incidents
or responses to such incidents; the timing and acceptance of the Company's new
product and services offerings; financial market conditions and the results of
financing efforts; weather and other natural phenomena; the ability of the
Company to obtain additional generating capacity at competitive prices; and
other factors discussed elsewhere herein and in other reports (including Form
10-K) filed from time to time by the Company with the Securities and Exchange
Commission.
II-128
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Gulf Power Company 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $584,591 $548,640 $516,949
Sales for resale --
Non-affiliates 82,252 66,890 62,354
Affiliates 27,256 66,995 66,110
Other revenues 31,104 31,794 28,686
- ------------------------------------------------------------------------------------------------------------------
Total operating revenues 725,203 714,319 674,099
- ------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 200,633 215,744 209,031
Purchased power --
Non-affiliates 65,585 73,846 46,332
Affiliates 40,660 8,644 10,703
Other 117,394 117,146 114,670
Maintenance 60,193 56,281 57,830
Depreciation and amortization 68,218 66,873 64,589
Taxes other than income taxes 55,261 55,904 51,782
- ------------------------------------------------------------------------------------------------------------------
Total operating expenses 607,944 594,438 554,937
- ------------------------------------------------------------------------------------------------------------------
Operating Income 117,259 119,881 119,162
Other Income (Expense):
Interest income 1,258 1,137 1,771
Other, net 2,710 (4,126) (1,357)
- ------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 121,227 116,892 119,576
- ------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 25,034 28,085 26,861
Distributions on preferred securities of subsidiary 6,477 6,200 6,200
- ------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 31,511 34,285 33,061
- ------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 89,716 82,607 86,515
Income taxes (Note 7) 31,260 30,530 32,631
- ------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 58,456 52,077 53,884
Accounting Change
Cumulative effect of accounting change--
less income taxes of $42 thousand 68 - -
- ------------------------------------------------------------------------------------------------------------------
Net Income 58,524 52,077 53,884
Dividends on Preferred Stock 217 234 217
- ------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 58,307 $ 51,843 $ 53,667
==================================================================================================================
The accompanying notes are an integral part of these statements.
II-129
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Gulf Power Company 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 58,524 $ 52,077 $ 53,884
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 72,320 69,915 68,721
Deferred income taxes, net 3,394 (12,516) (6,609)
Other, net (1,804) 10,686 3,735
Changes in certain current assets and liabilities --
Receivables, net 15,991 (20,212) (10,484)
Fossil fuel stock (30,887) 13,101 (5,656)
Materials and supplies 176 1,055 (2,063)
Accounts payable (14,492) 15,924 (2,023)
Provision for rate refund 1,530 7,203 -
Other (31,249) 12,521 7,030
- ------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 73,503 149,754 106,535
- ------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (274,668) (95,807) (69,798)
Other 5,290 (4,432) (8,856)
- ------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (269,378) (100,239) (78,654)
- ------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 44,311 (12,000) 23,500
Proceeds --
Other long-term debt 135,000 - 50,000
Preferred securities 30,000 - -
Capital contributions from parent company 72,484 12,222 2,294
Retirements --
First mortgage bonds (30,000) - -
Other long-term debt (862) (1,853) (27,074)
Preferred stock - - -
Payment of preferred stock dividends (217) (234) (271)
Payment of common stock dividends (53,275) (59,000) (61,300)
Other (3,703) (22) (246)
- ------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 193,738 (60,887) (13,097)
- ------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (2,137) (11,372) 14,784
Cash and Cash Equivalents at Beginning of Period 4,381 15,753 969
- ------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 2,244 $ 4,381 $ 15,753
========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $30,813 $32,277 $27,670
Income taxes (net of refunds) 33,349 42,252 29,462
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-130
BALANCE SHEETS
At December 31, 2001 and 2000
Gulf Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- -------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 2,244 $ 4,381
Receivables --
Customer accounts receivable 64,113 69,820
Other accounts and notes receivable 4,316 2,179
Affiliated companies 2,689 15,026
Accumulated provision for uncollectible accounts (1,342) (1,302)
Fossil fuel stock, at average cost 47,655 16,768
Materials and supplies, at average cost 28,857 29,033
Regulatory clauses under recovery 24,912 2,112
Other 12,662 6,543
- -------------------------------------------------------------------------------------------------------------
Total current assets 186,106 144,560
- -------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,951,512 1,892,023
Less accumulated provision for depreciation 912,581 867,260
- -------------------------------------------------------------------------------------------------------------
1,038,931 1,024,763
Construction work in progress 264,525 71,008
- -------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,303,456 1,095,771
- -------------------------------------------------------------------------------------------------------------
Other Property and Investments 7,049 4,510
- -------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 7) 16,766 15,963
Prepaid pension costs (Note 2) 26,364 20,058
Debt expense, being amortized 3,036 2,392
Premium on reacquired debt, being amortized 14,518 15,866
Other 12,222 12,944
- -------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 72,906 67,223
- -------------------------------------------------------------------------------------------------------------
Total Assets $1,569,517 $1,312,064
=============================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-131
BALANCE SHEETS
At December 31, 2001 and 2000
Gulf Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2001 2000
- --------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Notes payable $ 87,311 $ 43,000
Accounts payable --
Affiliated 18,202 17,558
Other 38,308 38,153
Customer deposits 14,506 13,474
Taxes accrued --
Income taxes 8,162 3,864
Other 8,053 8,749
Interest accrued 8,305 8,324
Provision for rate refund 1,530 7,203
Vacation pay accrued 4,725 4,512
Regulatory clauses over recovery 3,719 6,848
Other 6,528 1,584
- --------------------------------------------------------------------------------------------------------------
Total current liabilities 199,349 153,269
- --------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 467,784 365,993
- --------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 161,968 155,074
Deferred credits related to income taxes (Note 7) 28,293 38,255
Accumulated deferred investment tax credits 24,056 25,792
Employee benefits provisions 37,892 31,075
Other 26,045 25,992
- --------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 278,254 276,188
- --------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 115,000 85,000
- --------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 4,236 4,236
- --------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 504,894 427,378
- --------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,569,517 $1,312,064
==============================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-132
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Gulf Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long Term Debt:
First mortgage bonds --
Maturity Interest Rates
--------- --------------
July 1, 2003 6.125% $ - $ 30,000
November 1, 2006 6.50% 25,000 25,000
January 1, 2026 6.875% 30,000 30,000
- -----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 55,000 85,000
- -----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
4.69% due August 1, 2003 60,000 -
7.05% due August 15, 2004 50,000 50,000
6.10% due September 30, 2016 75,000 -
7.50% due June 30, 2037 20,000 20,000
6.70% due June 30, 2038 47,211 48,073
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 252,211 118,073
- -----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.25% to 6.30% due 2006-2026 108,700 108,700
Non-collateralized:
Variable rates (1.75% to 1.95% at 1/1/02)
due 2022-2024 60,930 60,930
- -----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 169,630 169,630
- -----------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (9,057) (6,710)
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $29.2 million) 467,784 365,993 42.9% 41.5%
- -----------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value, 4.64% to 5.44% 4,236 4,236
- -----------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $0.2 million) 4,236 4,236 0.4% 0.5%
- -----------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
7.00% 45,000 45,000
7.38% 30,000 -
7.63% 40,000 40,000
- -----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $8.4 million) 115,000 85,000 10.5% 9.6%
- -----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized and outstanding -
992,717 shares in 2001 and 2000 38,060 38,060
Paid-in capital 305,960 233,476
Premium on preferred stock 12 12
Retained earnings 160,862 155,830
- -----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 504,894 427,378 46.2% 48.4%
- -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $1,091,914 $882,607 100.0% 100.0%
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-133
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Gulf Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1999 $38,060 $218,960 $12 $170,620 $427,652
Net income after dividends on preferred stock - - - 53,667 53,667
Capital contributions from parent company - 2,294 - - 2,294
Cash dividends on common stock - - - (51,300) (51,300)
Other - - - (10,000) (10,000)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 38,060 221,254 12 162,987 422,313
Net income after dividends on preferred stock - - - 51,843 51,843
Capital contributions from parent company - 12,222 - - 12,222
Cash dividends on common stock - - - (59,000) (59,000)
Balance at December 31, 2000 38,060 233,476 12 155,830 427,378
- -----------------------------------------------------------------------------------------------------------------------------
Net income after dividends on preferred stock - - - 58,307 58,307
Capital contributions from parent company - 72,484 - - 72,484
Cash dividends on common stock - - - (53,275) (53,275)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $38,060 $305,960 $12 $160,862 $504,894
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-134
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2001 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Gulf Power Company (Company) is a wholly owned subsidiary of Southern Company,
which is the parent company of five operating companies, a system service
company (SCS), Southern Communications Services (Southern LINC), Southern
Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern
Power), and other direct and indirect subsidiaries. The operating companies --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- provide electric service in four southeastern states. Contracts
among the operating companies -- related to jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. SCS provides, at cost, specialized services
to Southern Company and subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Power was
established in 2001 to construct, own, and manage Southern Company's competitive
generation assets and sell electricity at market-based rates in the wholesale
market.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Florida Public Service Commission
(FPSC). The Company follows accounting principles generally accepted in the
United States and complies with the accounting policies and practices prescribed
by the FPSC and the FERC. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the
use of estimates, and the actual results may differ from those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Affiliate Transactions
The Company has an agreement with 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 administration, human resources,
systems and procedures, and other services with respect to business and
operations and power pool operations. Costs for these services amounted to $45
million, $44 million, and $43 million during 2001, 2000, and 1999, 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. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:
2001 2000
--------------------------
(in thousands)
Deferred income tax charges $ 16,766 $ 15,963
Deferred loss on reacquired
debt 14,518 15,866
Environmental remediation 7,163 7,638
Vacation pay 4,725 4,512
Accumulated provision for
rate refunds (1,530) (7,203)
Accumulated provision for
property damage (13,565) (8,731)
Deferred income tax credits (28,293) (38,255)
Other, net (1,443) (1,074)
- ------------------------------------------------------------------
Total $ (1,659) $(11,284)
==================================================================
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 any impairment to other assets, including plant, and write down the
assets, if impaired, to their fair value.
II-135
NOTES (continued)
Gulf Power Company 2001 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its service area located in northwest
Florida and to wholesale customers in the Southeast.
Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period.
Fuel costs are expensed as the fuel is used. The Company's retail electric
rates include provisions to annually adjust billings for fluctuations in fuel
costs, the energy component of purchased power costs, and certain other costs.
The Company also has similar retail cost recovery clauses for energy
conservation costs, purchased power capacity costs, and environmental compliance
costs. Revenues are adjusted monthly for differences between recoverable costs
and amounts actually reflected in current rates.
The Company has a diversified base of customers and no single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts averaged significantly less than 1 percent of revenues.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.7 percent in 2001 and
3.8 percent in both 2000, and 1999. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to 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. Also,
the provision for depreciation expense includes an amount for the expected cost
of removal of facilities.
Other Income
Other income consists principally of interest and dividend income, Allowance for
Funds Used During Construction (AFUDC)-equity, and income or expenses on other
non-regulated activities. In 2000 and 1999, the non-regulated activities
included the results of the Company's merchandising operations, which were
discontinued in the latter part of 2000.
Income Taxes
The Company uses the liability method of accounting for 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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction. The cost of
maintenance, repairs, and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property (exclusive of minor
items of property) is charged to utility plant.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in
circumstances indicate that the carrying value of such assets may not be
recoverable. The determination of whether an impairment has occurred is based on
an estimate of undiscounted future cash flows attributable to the assets, as
compared to the carrying value of the assets. If an impairment has occurred, the
amount of the impairment recognized is determined by estimating the fair value
of the assets and recording a provision for loss if the carrying value is
greater than the fair value. For assets identified as held for sale, the
carrying value is compared to the estimated fair value less the cost to sell in
order to determine if an impairment provision is required. Until the assets are
disposed of, their estimated fair value is re-evaluated when circumstances or
events change.
Cash and Cash Equivalents
Temporary cash investments are considered cash equivalents. Temporary cash
investments are securities with original maturities of 90 days or less.
Financial Instruments
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on
net income was immaterial.
II-136
NOTES (continued)
Gulf Power Company 2001 Annual Report
The Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, and certain commodity prices. Gains and losses
on qualifying hedges are deferred and recognized either in income or as an
adjustment to the carrying amount of the hedged item when the transaction
occurs.
The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.
The Company and its affiliates, through SCS acting as their agent, enters
into commodity related forward and option contracts to limit exposure to
changing prices on certain fuel purchases and electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales contracts
meet the definition of a derivative under FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities. In many cases, these fuel and
electricity contracts qualify for normal purchase and sale exceptions under
Statement No. 133 and are accounted for under the accrual method. Other
contracts qualify as cash flow hedges of anticipated transactions, resulting in
the deferral of related gains and losses, and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.
Other financial instruments for which the carrying amount did not equal fair
value at December 31 were as follows:
Carrying Fair
Amount Value
---------------------------
(in thousands)
Long-term debt:
At December 31, 2001 $467,784 $474,911
At December 31, 2000 $365,993 $364,697
Capital trust preferred
securities:
At December 31, 2001 $115,000 $114,898
At December 31, 2000 $85,000 $80,988
- --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on
either closing market prices or closing prices of comparable instruments.
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.
Provision for Injuries and Damages
The Company is subject to claims and suits arising in the ordinary course of
business. As permitted by regulatory authorities, the Company provides for the
uninsured costs of injuries and damages by charges to income amounting to $1.2
million annually. The expense of settling claims is charged to the provision to
the extent available. The accumulated provision of $1.3 million and $1.2 million
at December 31, 2001 and 2000, respectively, is included in other current
liabilities in the accompanying Balance Sheets.
Provision for Property Damage
The Company provides for the cost of repairing damages from major storms and
other uninsured property damages. This includes the full cost of major storms
and other damages to its transmission and distribution lines and the cost of
uninsured damages to its generation and other property. The expense of such
damages is charged to the provision account. At December 31, 2001 and 2000, the
accumulated provision for property damage was $13.6 million and $8.7 million,
respectively. The FPSC approved annual accrual to the accumulated provision for
property damage is $3.5 million, with a target level for the accumulated
provision account between $25.1 and $36.0 million. The FPSC has also given the
Company the flexibility to increase its annual accrual amount above $3.5 million
at the Company's discretion. The Company accrued $4.5 million in 2001, $3.5
million in 2000, and $5.5 million in 1999 to the accumulated provision for
property damage. The Company had a net credit of $(0.3) million to the provision
account in 2001 related to insurance proceeds that exceeded actual claims. In
2000 and 1999, the Company charged $0.3 million and $1.6 million, respectively,
to the provision account.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. The Company provides certain medical
care and life insurance benefits for retired employees. Substantially all
employees may become eligible for these benefits when they retire. Trusts are
II-137
NOTES (continued)
Gulf Power Company 2001 Annual Report
funded to the extent required by the Company's regulatory commissions. In late
2000, the Company adopted several pension and postretirement benefit plan
changes that had the effect of increasing benefits to both current and future
retirees. The measurement date for plan assets and obligations is September 30
for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
2001 2000
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $153,214 $146,106
Service cost 4,703 4,367
Interest cost 11,644 10,695
Benefits paid (8,105) (7,169)
Actuarial gain and
employee transfers, net (195) (785)
Amendments 7,997 -
Other (7) -
- ---------------------------------------------------------------
Balance at end of year $169,251 $153,214
===============================================================
Plan Assets
--------------------------
2001 2000
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $283,266 $241,485
Actual return on plan assets (40,841) 43,833
Benefits paid (7,758) (6,973)
Employee transfers (961) 4,921
- ---------------------------------------------------------------
Balance at end of year $233,706 $283,266
===============================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2001 2000
- ---------------------------------------------------------------
(in thousands)
Funded status $ 64,455 $ 130,052
Unrecognized transition
obligation (2,832) (3,503)
Unrecognized prior
service cost 11,689 4,529
Unrecognized net gain (47,038) (111,092)
4th quarter cash flow
adjustment 90 72
---------------------------------------------------------------
Prepaid asset recognized
in the Balance Sheets $ 26,364 $20,058
===============================================================
Components of the pension plan's net periodic cost
were as follows:
2001 2000 1999
- -------------------------------------------------------------------
Service cost $ 4,703 $ 4,367 $ 4,556
Interest cost 11,644 10,695 9,729
Expected return on
plan assets (19,312) (17,504) (15,968)
Recognized net gain (3,072) (2,582) (234)
Net amortization 165 (235) (1,549)
- -------------------------------------------------------------------
Net pension income $ (5,872) $ (5,259) $ (3,466)
===================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations
and in the fair value of plan assets were as follows:
Accumulated
Benefit Obligations
---------------------------
2001 2000
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $50,025 $48,010
Service cost 983 896
Interest cost 3,886 3,515
Benefits paid (1,823) (1,462)
Amendments 3,412 -
- ---------------------------------------------------------------
Actuarial gain (2,146) (934)
- ---------------------------------------------------------------
Balance at end of year $54,337 $50,025
===============================================================
Plan Assets
---------------------------
2001 2000
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $13,388 $11,196
Actual return on plan assets (1,830) 2,079
Employer contributions 1,897 1,575
Benefits paid (1,823) (1,462)
- ---------------------------------------------------------------
Balance at end of year $11,632 $13,388
===============================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
2001 2000
- ----------------------------------------------------------------
(in thousands)
Funded status $(42,705) $(36,638)
Unrecognized transition
obligation 4,012 4,368
Unrecognized prior
service cost 5,695 2,582
Unrecognized net loss 1,235 496
Fourth quarter contributions 386 316
- ----------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(31,377) $(28,876)
================================================================
II-138
NOTES (continued)
Gulf Power Company 2001 Annual Report
Components of the postretirement plan's net periodic cost were as follows:
2001 2000 1999
- -----------------------------------------------------------------
Service cost $ 983 $ 896 $ 1,087
Interest cost 3,886 3,515 3,261
Expected return on
plan assets (1,037) (901) (794)
Transition obligation 356 355 356
Prior service cost 299 159 159
Recognized net
(gain)/loss (18) 13 264
- -----------------------------------------------------------------
Net post-retirement cost $ 4,469 $ 4,037 $ 4,333
=================================================================
The weighted average rates assumed in the actuarial calculations for both the
pension plan and postretirement benefits plan were:
2001 2000
- ----------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00% 5.00%
Long-term return on plan
assets 8.50% 8.50%
- ----------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter.
An annual increase or decrease in the assumed medical care cost trend rate
of 1 percent would affect the accumulated benefit obligation and the service and
interest cost components at December 31, 2001 as follows (in thousands):
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
Benefit obligation $4,575 $3,985
Service and interest costs $410 $351
===============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $2.3
million, $2.2 million, and $2.0 million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.
Environmental Cost Recovery
In 1993, the Florida Legislature adopted legislation for an Environmental Cost
Recovery Clause (ECRC), which allows a utility to petition the FPSC for recovery
of prudent environmental compliance costs that are not being recovered through
base rates or any other recovery mechanism. Such environmental costs include
operation and maintenance expense, emission allowance expense, depreciation, and
a return on invested capital.
In 1994, the FPSC approved the Company's initial petition under the ECRC for
recovery of environmental costs. During 2001, 2000, and 1999, the Company
recorded ECRC revenues of $10.0 million, $9.9 million, and $11.5 million,
respectively.
At December 31, 2001, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $7.2 million. These
estimated costs are expected to be expended from 2002 through 2008. These
projects have been approved by the FPSC for recovery through the ECRC discussed
above. Therefore, the Company recorded $1.2 million in current assets and
current liabilities and $6.0 million in deferred assets and deferred liabilities
representing the future recoverability of these costs.
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and SCS.
The complaint alleges violations of the prevention of significant deterioration
and new source review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
II-139
NOTES (continued)
Gulf Power Company 2001 Annual Report
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation
at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day.
The EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. See Note 5
under "Joint Ownership Agreements" related to the Company's ownership interest
in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a
motion to amend its complaint to add the violations alleged in its notice of
violation, and to add the Company, Mississippi Power, and Savannah Electric as
defendants. The complaint and notice of violation are similar to those brought
against and issued to several other electric utilities. These complaints and
notices of violation allege that the utilities had failed to secure necessary
permits or install additional pollution control equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. On August 1, 2000, the U.S. District Court granted
Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and
granted SCS's motion to dismiss on the grounds that it neither owned nor
operated the generating units involved in the proceedings. The court directed
the EPA to re-file its amended complaint limiting claims to those brought
against Georgia Power and Savannah Electric. The EPA re-filed those claims as
directed by the court. Also, the EPA re-filed its claims against Alabama Power
in U.S. District Court in Alabama. It has not re-filed against the Company,
Mississippi Power, or the system service company. The Alabama Power, Georgia
Power, and Savannah Electric cases have been stayed since the spring of 2001,
pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
appeal of a very similar New Source Review enforcement action against the
Tennessee Valley Authority (TVA). The TVA case involves many of the same legal
issues raised by the actions against Alabama Power, Georgia Power, and Savannah
Electric. Because the outcome of the TVA case could have a significant adverse
impact on Alabama Power and Georgia Power, both companies are parties to that
case as well. The U.S. District Court in Alabama has indicated that it will
revisit the issue of a continued stay in April 2002. The U.S. District Court in
Georgia is currently considering a motion by the EPA to reopen the Georgia case.
Georgia Power and Savannah Electric have opposed that motion.
The Company believes that it has complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place.
An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
Retail Revenue Sharing Plan
In early 1999, the FPSC staff and the Company became involved in discussions
primarily related to reducing the Company's authorized rate of return. On
October 1, 1999, the Office of Public Counsel, the Coalition for Equitable
Rates, the Florida Industrial Power Users Group, and the Company jointly filed a
petition to resolve the issues. The stipulation included a reduction to retail
base rates of $10 million annually and provided for revenues to be shared within
set ranges for 1999 through 2002. Customers receive two-thirds of any revenue
within the sharing range and the Company retains one-third. Any revenue above
this range is refunded to the customers. The stipulation also included
authorization for the Company, at its discretion, to accrue up to an additional
$5 million to the property insurance reserve and $1 million to amortize a
regulatory asset related to the corporate office. The Company also filed a
request to prospectively reduce its authorized return on equity (ROE) range from
11 to 13 percent to 10.5 to 12.5 percent in order to help ensure that the FPSC
would approve the stipulation. The FPSC approved both the stipulation and the
ROE request with an effective date of November 4, 1999.
The Company's retail revenue range for sharing was $358 million to $374
million in calendar year 2001, and $352 million to $368 million in 2000, to be
shared between the Company and its retail customers on the one-third/two-thirds
basis. Actual retail revenues in 2001 were $360.3 million and $362.4 million in
2000. The Company recorded revenues subject to refund of $1.5 million in 2001
and $6.9 million in 2000. The estimated refund with interest was $0.03 million
in 2001 and $0.3 million in 2000 and was reflected in customer billings in
February 2002 and 2001 respectively. In addition to the refund, the Company
amortized $1 million of the regulatory assets related to the corporate office in
2001 and 2000, and accrued an additional $1.0 million to the property insurance
II-140
NOTES (continued)
Gulf Power Company 2001 Annual Report
reserve in 2001. For calendar year 2002, there are specified sharing ranges for
each month from the expected in-service date of Smith Unit 3 until the end of
the year. The sharing plan will expire at the earlier of the in-service date of
Smith Unit 3 or December 31, 2002.
Retail Rate Case
On September 10, 2001, the Company filed a request with the FPSC for a base rate
increase of approximately $70 million, the majority of which is needed to
recover costs related to the Smith Unit 3 combined cycle facility currently
under construction and scheduled to be placed in service by June 2002. Hearings
are scheduled for February 25 through March 1, 2002 with a decision expected in
early May 2002 and new rates effective June 6, 2002.
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $103 million in 2002, $72 million in 2003, and
$107 million in 2004. The construction program is subject to periodic review and
revision, and actual construction costs may vary from the above estimates
because of numerous factors. These factors include changes in business
conditions; revised load growth estimates; changes in environmental regulations;
increasing costs of labor, equipment, and materials; and cost of capital. At
December 31, 2001, significant purchase commitments were outstanding in
connection with the construction program. The Company has budgeted $24.3 million
in 2002 as the remaining cost of a 574 megawatt combined cycle gas generating
unit to be located in the eastern portion of its service area. The unit is
expected to have an in-service date of June 2002. The Company's remaining
construction program is related to maintaining and upgrading the transmission,
distribution, and generating facilities.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into contract commitments for the procurement of fuel. In
some cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Total estimated obligations at
December 31, 2001 were as follows:
Year Fuel
--------- ----------------
(in millions)
2002 $140
2003 109
2004 112
2005 113
2006 115
2007-2025 398
----------------------------------------------------------
Total commitments $987
==========================================================
In addition, SCS acts as agent for the five operating companies and Southern
Power with regard to natural gas purchases. Natural gas purchases (in dollars)
are based on various indices at the actual time of delivery; therefore, only the
volume commitments are firm. The Company's committed volumes are allocated based
on usage projections as of December 31 as follows:
Year Natural Gas
--------- ----------------
(MMBtu)
2002 14,194,988
2003 28,377,592
2004 15,071,438
2005 6,913,093
2006 4,187,658
2007 and thereafter 1,676,250
------------------------------------------------------
Total commitments 70,421,019
======================================================
Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.
Lease Agreements
In 1989, the Company and Mississippi Power jointly entered into a twenty-two
year operating lease agreement for the use of 495 aluminum railcars. In 1994, a
second lease agreement for the use of 250 additional aluminum railcars was
entered into for twenty-two years. Both of these leases are for the
transportation of coal to Plant Daniel. At the end of each lease term, the
Company has the option to purchase the 745 railcars at the greater of lease
termination value or fair market value, or to renew the leases at the end of the
lease term.
II-141
NOTES (continued)
Gulf Power Company 2001 Annual Report
The Company, as a joint owner of Plant Daniel, is responsible for one half of
the lease costs. The lease costs are charged to fuel inventory and are allocated
to fuel expense as the fuel is used. The Company's share of the lease costs
charged to fuel inventories was $1.9 million in 2001 and $2.4 million in 2000.
The annual amounts for 2002 through 2006 are expected to be $1.9 million, $1.9
million, $1.9 million, $2.0 million, and $2.0 million, respectively, and after
2006 are expected to total $11.7 million.
5. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel Unit No. 1 and Unit
No. 2. Plant Daniel is a generating plant located in Jackson County,
Mississippi. In accordance with the operating agreement, Mississippi Power
acts as the Company's agent with respect to the construction, operation, and
maintenance of these units.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant
Scherer is a generating plant located near Forsyth, Georgia. In accordance with
the operating agreement, Georgia Power acts as the Company's agent with respect
to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is included
in the corresponding operating expense accounts in the Statements of Income.
At December 31, 2001, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:
Plant Plant
Scherer Daniel Unit
Unit No. 3 Nos. 1 & 2
(coal-fired) (coal-fired)
-----------------------------
(in thousands)
Plant In Service $184,901(1) $228,278
Accumulated Depreciation $73,684 $120,646
Construction Work in Progress $1,556 $6,174
Nameplate Capacity (2)
(megawatts) 205 500
Ownership 25% 50%
- ------------------------------------------------------------------
(1) Includes net plant acquisition adjustment.
(2) Total megawatt nameplate capacity:
Plant Scherer Unit No. 3: 818
Plant Daniel Unit Nos. 1&2: 1,000
6. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity to certain non-affiliated utilities located
outside the system's service area. The unit power sales agreements 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 capacity revenues from these sales
were $19.5 million in 2001, $20.3 million in 2000, and $19.8 million in 1999.
Unit power from specific generating plants of Southern Company is currently
being sold to Florida Power Corporation (FPC), Florida Power & Light Company
(FP&L), and Jacksonville Electric Authority (JEA). Under these agreements, 210
megawatts of net dependable capacity were sold by the Company during 2001. Sales
will remain close to that level, unless reduced by FP&L, FPC, and JEA with a
minimum of three years notice, until the expiration of the contracts in 2010.
7. INCOME TAXES
At December 31, 2001, the tax-related regulatory assets to be recovered from
customers were $16.8 million. These assets are attributable to tax benefits
flowed through to customers in prior years and to taxes applicable to
capitalized allowance for funds used during construction. At December 31, 2001,
the tax-related regulatory liabilities to be credited to customers were $28.3
million. 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 federal and state income tax provisions are as follows:
2001 2000 1999
----------------------------------
(in thousands)
Total provision for income taxes:
Federal--
Current $24,207 $37,250 $33,973
Deferred 2,568 (11,159) (6,107)
26,775 26,091 27,866
- ------------------------------------------------------------------
State--
Current 3,701 5,796 5,267
Deferred 826 (1,357) (502)
4,527 4,439 4,765
- ------------------------------------------------------------------
Total $31,302 $30,530 $32,631
==================================================================
II-142
NOTES (continued)
Gulf Power Company 2001 Annual Report
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
2001 2000
---------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $179,071 $172,646
Other 27,328 14,262
- ---------------------------------------------------------------------
Total 206,399 186,908
- ---------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 9,009 8,703
Postretirement benefits 9,379 9,205
Other 17,881 14,742
- ---------------------------------------------------------------------
Total 36,269 32,650
- ---------------------------------------------------------------------
Net deferred tax liabilities 170,130 154,258
Less current portion, net (8,162) (816)
- ---------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $161,968 $155,074
=====================================================================
Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation and amortization in the Statements of Income. Credits amortized in
this manner amounted to $1.7 million in 2001 and $1.9 million in each of 2000
and 1999. At December 31, 2001, all investment tax credits available to reduce
federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
2001 2000 1999
---------------------------
Federal statutory rate 35% 35% 35%
State income tax,
net of federal deduction 4 4 4
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (2) (2) (2)
Other, net (3) (1) -
- ---------------------------------------------------------------
Effective income tax rate 35% 37% 38%
===============================================================
The Company and the other subsidiaries of Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each subsidiary's current and deferred tax expense is computed on a
stand-alone basis. In accordance with Internal Revenue Service regulations, each
company is jointly and severally liable for the tax liability.
8. CAPITALIZATION
Preferred Securities
In January 1997, Gulf Power Capital Trust I (Trust I), of which the Company owns
all of the common securities, issued $40 million of 7.625 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust I are
$41 million aggregate principal amount of the Company's 7.625 percent junior
subordinated notes due December 31, 2036.
In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company
owns all of the common securities, issued $45 million of 7.0 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust II are
$46 million aggregate principal amount of the Company's 7.0 percent junior
subordinated notes due December 31, 2037.
In November 2001, Gulf Power Capital Trust III (Trust III), of which the
Company owns all of the common securities, issued $30 million of 7.375 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust III are $31 million aggregate principal amount of the Company's 7.375
percent junior subordinated notes due September 30, 2041.
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 payment obligations with respect to the preferred
securities of Trust I, Trust II, and Trust III. Trust I, Trust II, and Trust III
are subsidiaries of the Company, and accordingly are consolidated in the
Company's financial statements.
Securities Due Within One Year
At December 31, 2001, the Company had an improvement fund requirement of
$550,000. The first mortgage bond improvement fund requirement amounts to 1
percent of each outstanding series of bonds authenticated under the indenture
prior to January 1 of each year, other than those issued to collateralize
pollution control revenue bond obligations. The requirement may be satisfied by
depositing cash, reacquiring bonds, or by pledging additional property equal to
1 and 2/3 times the requirement.
The sinking fund requirements of first mortgage bonds were satisfied by
certifying property additions in 2001 and 2000. It is anticipated that the 2002
II-143
NOTES (continued)
Gulf Power Company 2001 Annual Report
requirement will be satisfied by certifying property additions. Sinking fund
requirements and/or maturities through 2006 applicable to long-term debt are as
follows: none in 2002; $60.6 million in 2003; $50.6 million on 2004; none in
2005; and $37.6 million in 2006.
Dividend Restrictions
The Company's first mortgage bond indenture contains various common stock
dividend restrictions, which remain in effect as long as the bonds are
outstanding. At December 31, 2001, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.
Bank Credit Arrangements
At December 31, 2001, the Company had $41.5 million of lines of credit with
banks subject to renewal June 1 of each year, of which $41.5 million remained
unused. In addition, the Company has two unused committed lines of credit
totaling $61.9 million that were established for liquidity support of its
variable rate pollution control bonds. In connection with these credit lines,
the Company has agreed to pay commitment fees and/or to maintain compensating
balances with the banks. The compensating balances, which represent
substantially all of the cash of the Company except for daily working funds and
like items, are not legally restricted from withdrawal.
The Company borrows through commercial paper programs that have the liquidity
support of committed bank credit arrangements. In addition, the Company from
time to time borrows under uncommitted lines of credit with banks. The amount of
commercial paper outstanding at December 31, 2001 was $37.4 million.
In addition, the Company has bid-loan facilities with five major money center
banks that total $110 million, of which $50 million was committed at December
31, 2001.
Assets Subject to Lien
The Company's mortgage, which secures the first mortgage bonds issued by the
Company, constitutes a direct first lien on substantially all of the Company's
fixed property and franchises.
9. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 2001 and 2000 are as follows:
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
- --------------------------------------------------------------------
(in thousands)
March 2001 $165,029 $24,785 $10,196
June 2001 180,430 30,702 14,770
September 2001 226,616 45,504 26,657
December 2001 153,128 16,268 6,684
March 2000 $138,498 $16,007 $4,653
June 2000 182,120 30,505 12,927
September 2000 232,533 52,614 26,438
December 2000 161,168 20,755 7,825
- --------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-144
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Gulf Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $725,203 $714,319 $674,099 $650,518 $625,856
Net Income after Dividends
on Preferred Stock (in thousands) $58,307 $51,843 $53,667 $56,521 $57,610
Cash Dividends
on Common Stock (in thousands) $53,275 $59,000 $61,300 $57,200 $64,600
Return on Average Common Equity (percent) 12.51 12.20 12.63 13.20 13.33
Total Assets (in thousands) $1,569,517 $1,312,064 $1,308,495 $1,267,901 $1,265,612
Gross Property Additions (in thousands) $274,668 $95,807 $69,798 $69,731 $54,289
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $504,894 $427,378 $422,313 $427,652 $428,718
Preferred stock 4,236 4,236 4,236 4,236 13,691
Company obligated mandatorily
redeemable preferred securities 115,000 85,000 85,000 85,000 40,000
Long-term debt 467,784 365,993 367,449 317,341 296,993
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $1,091,914 $882,607 $878,998 $834,229 $779,402
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.2 48.4 48.0 51.3 55.0
Preferred stock 0.4 0.5 0.5 0.5 1.8
Company obligated mandatorily
redeemable preferred securities 10.5 9.6 9.7 10.2 5.1
Long-term debt 42.9 41.5 41.8 38.0 38.1
- ---------------------------------------------------------------------------------------------------------------------------------
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+ AA- AA- AA-
Fitch A+ AA- AA- AA- AA-
Preferred Stock -
Moody's Baa1 a2 a2 a2 a2
Standard and Poor's BBB+ BBB+ A- A A
Fitch A- A A A+ A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 A2
Standard and Poor's A A A A A
Fitch A A+ A+ A+ A+
=================================================================================================================================
Customers (year-end):
Residential 327,128 321,731 315,240 307,077 300,257
Commercial 48,654 47,666 47,728 46,370 44,589
Industrial 270 280 267 257 267
Other 468 442 316 268 264
- ---------------------------------------------------------------------------------------------------------------------------------
Total 376,520 370,119 363,551 353,972 345,377
=================================================================================================================================
Employees (year-end): 1,309 1,327 1,339 1,328 1,328
- ---------------------------------------------------------------------------------------------------------------------------------
II-145
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Gulf Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 313,165 $302,210 $ 279,238 $ 279,621 $ 276,924
Commercial 188,759 177,047 167,305 163,207 163,751
Industrial 81,719 74,095 68,222 71,119 77,045
Other 948 (4,712) 2,184 2,113 2,077
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 584,591 548,640 516,949 516,060 519,797
Sales for resale - non-affiliates 82,252 66,890 62,354 61,893 63,697
Sales for resale - affiliates 27,256 66,995 66,110 42,642 16,760
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 694,099 682,525 645,413 620,595 600,254
Other revenues 31,104 31,794 28,686 29,923 25,602
- --------------------------------------------------------------------------------------------------------------------------------
Total $725,203 $714,319 $674,099 $650,518 $625,856
================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 4,716,404 4,790,038 4,471,118 4,437,558 4,119,492
Commercial 3,417,427 3,379,449 3,222,532 3,111,933 2,897,887
Industrial 2,018,206 1,924,749 1,846,237 1,833,575 1,903,050
Other 21,208 18,730 19,296 18,952 18,101
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 10,173,245 10,112,966 9,559,183 9,402,018 8,938,530
Sales for resale - non-affiliates 2,093,203 1,705,486 1,561,972 1,341,990 1,531,179
Sales for resale - affiliates 962,892 1,916,526 2,511,983 1,758,150 848,135
- --------------------------------------------------------------------------------------------------------------------------------
Total 13,229,340 13,734,978 13,633,138 12,502,158 11,317,844
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.64 6.31 6.25 6.30 6.72
Commercial 5.52 5.24 5.19 5.24 5.65
Industrial 4.05 3.85 3.70 3.88 4.05
Total retail 5.75 5.43 5.41 5.49 5.82
Sales for resale 3.58 3.70 3.15 3.37 3.38
Total sales 5.25 4.97 4.73 4.96 5.30
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,497 14,992 14,318 14,577 13,894
Residential Average Annual
Revenue Per Customer $962.57 $945.87 $894.18 $918.56 $933.99
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,188 2,188 2,188 2,188 2,174
Maximum Peak-Hour Demand (megawatts):
Winter 2,106 2,154 2,085 2,040 1,844
Summer 2,223 2,285 2,161 2,146 2,032
Annual Load Factor (percent) 57.5 55.4 55.2 55.3 55.5
Plant Availability Fossil-Steam (percent): 90.1 85.2 87.2 87.6 91.0
- --------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 81.2 87.8 89.8 89.2 87.1
Oil and gas 1.0 1.6 2.5 2.0 0.4
Purchased power -
From non-affiliates 6.5 7.6 5.9 5.5 3.5
From affiliates 11.3 3.0 1.8 3.3 9.0
- --------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
II-146
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-147
MANAGEMENT'S REPORT
Mississippi Power Company 2001 Annual Report
The management of Mississippi Power Company has prepared -- and is responsible
for -- the financial statements and related information included in this report.
These statements were prepared in accordance with accounting principles
generally accepted in the United States and necessarily include amounts that are
based on the best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of four independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Mississippi Power Company in conformity with accounting principles generally
accepted in the United States.
/s/Michael D. Garrett
Michael D. Garrett
President and Chief Executive Officer
/s/Michael W. Southern
Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer
February 13, 2002
II-148
REPORT OF INDEPENDENT PUBLIC ACCOUNTANT
To Mississippi Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Mississippi Power Company (a Mississippi corporation and a wholly owned
subsidiary of Southern Company) as of December 31, 2001 and 2000, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements (pages II-160 through II-176)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Mississippi Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-149
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 2001 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's 2001 net income after dividends on preferred stock
of $63.9 million increased $8.9 million over 2000 earnings of $55.0 million,
which were $0.2 million more than 1999 earnings of $54.8 million. Net income for
2001 was higher due to additional sales for resale primarily attributable to the
commercial operation of the new Plant Daniel Combined Cycle Units 3 and 4 and
lower interest expense.
Revenues
Operating revenues for the Company in 2001 and the changes from the prior year
are as follows:
Increase (Decrease)
Amount From Prior Year
------ ----------------
2001 2001 2000
---------------------------------------
(in thousands)
Retail --
Base Revenues $284,255 $ (3,000) $ (4,343)
Fuel cost recovery
and other 204,898 (6,398) 33,460
-----------------------------------------------------------------
Total retail 489,153 (9,398) 29,117
-----------------------------------------------------------------
Sales for resale --
Non-affiliates 204,623 58,692 14,927
Affiliates 85,652 57,737 8,469
-----------------------------------------------------------------
Total sales for resale 290,275 116,429 23,396
Other operating
revenues 16,637 1,432 2,085
-----------------------------------------------------------------
Operating revenues $796,065 $108,463 $ 54,598
=================================================================
Percent change 15.8% 8.6%
-----------------------------------------------------------------
Total retail revenues for 2001 decreased approximately 1.9 percent when
compared to 2000. The decrease resulted primarily from lower energy sales to
residential, commercial, and industrial customers as a result of mild weather
and a slowdown in manufacturing activity in the Company's service territory.
Retail revenues for 2000 reflected a 6.2 percent increase over the prior year
due to the continued growth in the service area, increased fuel revenues, and a
positive weather impact.
Fuel revenues generally represent the direct recovery of fuel expense
including purchased power. Therefore, changes in recoverable fuel expenses are
offset with corresponding changes in fuel revenues and have no effect on net
income.
Sales for resale to non-affiliates are influenced by those utilities' own
customer demand, plant availability, and the cost of their predominant fuels.
Included in sales for resale to non-affiliates are revenues from rural electric
cooperative associations and municipalities located in southeastern Mississippi.
Energy sales to these customers decreased 3.7 percent in 2001 and increased 10.9
percent in 2000, with the related revenues decreasing 2.4 percent and rising
10.8 percent, respectively. The customer demand experienced by these utilities
is determined by factors very similar to those of the Company. Revenues from
other sales outside the service area increased in 2001 when compared to 2000 as
a result of a new long term contract made possible by the commercial operation
of Plant Daniel Units 3 and 4.
Energy sales to affiliated companies within the Southern Company electric
system, as well as purchases, will vary from year to year depending on demand
and the availability and cost of generating resources at each company. These
sales do not have a significant impact on earnings.
Below is a breakdown of kilowatt-hour sales for 2001 and the percent change
for the last two years:
2001 Percent Change
------------- ---------------------------
KWH 2001 2000
(in millions) ---------------------------
Residential 2,163 (5.4)% 1.7%
Commercial 2,841 (1.5) 1.3
Industrial 4,276 (2.3) (0.7)
Other 40 (0.3) 2.5
-------------
Total retail 9,320 (2.8) 0.5
Sales for
Resale --
Non-affiliates 5,011 36.4 12.9
Affiliates 2,953 552.3 (16.2)
-------------
Total 17,284 26.0 2.8
==================================================================
Residential sales decreased 5.4 percent due to unusually mild weather in the
Company's service area. Commercial sales decreased 1.5 percent and industrial
sales fell 2.3 percent due to an economic slowdown. Total retail kilowatt-hour
sales increased slightly in 2000. This increase primarily resulted from the
continued growth in the service area, increased tourism, and the positive impact
of weather. Kilowatt-hour sales from outside the service area increased in 2001
when compared to 2000 as a result of a new contract made possible by the
II-150
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
commercial operation of Plant Daniel Combined Cycle Units 3 and 4. Again, sales
to affiliates will vary year to year depending on demand and cost of generating
resources at each company.
Expenses
Total operating expenses were $663 million in 2001, reflecting an increase of
$98 million or 17.4 percent over the prior year. The increase was due primarily
to the commercial operation of Plant Daniel Combined Cycle Units 3 and 4. In
2000, total operating expenses increased by 10.1 percent over the prior year due
primarily to higher fuel and purchased power expenses.
Fuel costs are the single largest expense for the Company. Fuel expenses for
2001 and 2000 increased 45.4 percent and 10.7 percent, respectively. The
increase for 2001 was due to increased generation especially from Plant Daniel
Combined Cycle Units 3 and 4 and a higher average cost of fuel. The 2000
increase was due to increased generation and a higher average cost of fuel.
In 2001, expenses related to purchased power from non-affiliates decreased
26.4 percent, while expenses related to purchased power from affiliates
increased 5.7 percent which, in total, resulted in a 11.1 percent decrease when
compared to 2000. This decrease in purchased power is primarily due to the
commercial operation of Plant Daniel Combined Cycle Units 3 and 4 and the
expiration of non-affiliated purchase power contracts in 2000. Sales and
purchases among the Company and its affiliates will vary from period to period
depending on demand and the availability and variable production cost of each
generating unit in the Southern Company electric system.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
2001 2000 1999
----------------------------
Total generation
(millions of kilowatt hours) 15,770 11,688 11,599
Sources of generation
(percent) --
Coal 59 83 81
Gas 41 17 19
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.89 1.80 1.65
- ----------------------------------------------------------------
Other operation expenses increased 17.2 percent in 2001 primarily due to an
increase in other production expenses due to the commercial operation of Plant
Daniel Combined Cycle Units 3 and 4. In 2000, other operation expense decreased
8.2 percent primarily due to a decrease in administrative and general expenses.
Maintenance expense in 2001 increased primarily due to the commercial operation
of Plant Daniel Combined Cycle Units 3 and 4, while maintenance expense in 2000
increased primarily due to additional scheduled maintenance. Depreciation and
amortization expense increased 7.6 percent in 2001 due to a growth in plant
investment and the amortization of the Company's regulatory asset related to its
Environmental Compliance Overview Plan (ECO Plan). In 2000, depreciation expense
increased slightly due to growth in plant investment and new depreciation rates,
which became effective January 2000.
Taxes other than income taxes decreased 7.6 percent in 2001 due to reduced
ad valorem taxes related to a change in the tax rate. These taxes increased 1.7
percent in 2000 due to higher municipal franchise taxes resulting from higher
retail revenues. Interest on long-term debt decreased in 2001 as a result of
lower interest rates on debt outstanding.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical costs does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
General
The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of the Company's
II-151
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
future earnings depends on numerous factors ranging from weather to energy sales
growth to a less regulated and more competitive environment. Expenses are
subject to constant review and cost control programs. The Company is also
maximizing the utility of invested capital and minimizing the need for
additional capital by refinancing outstanding obligations, managing the size of
its fuel stockpile, raising generating plant availability and efficiency, and
aggressively controlling its construction budget.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
southeastern Mississippi. Prices for electricity provided by the Company to
retail customers are set by the Mississippi Public Service Commission (MPSC)
under cost-based regulatory principles. The Federal Energy Regulatory Commission
(FERC) regulates the Company's wholesale rate schedules, power sales contracts,
and transmission facilities.
Operating revenues will be affected by any changes in rates under the
Performance Evaluation Plan (PEP) -- the Company's performance based ratemaking
plan -- and the ECO Plan. PEP has proven to be a stabilizing force on electric
rates, with only moderate changes in rates taking place. The ECO Plan provides
for recovery of costs (including costs of capital) associated with environmental
projects approved by the MPSC, most of which are required to comply with Clean
Air Act Amendments of 1990 (Clean Air Act) and the regulations thereunder. The
ECO Plan is operated independently of PEP. Compliance costs related to the Clean
Air Act could affect earnings if such costs cannot be recovered. The Company
filed its 2001 ECO Plan in January 2001 which was approved, as filed, by the
Mississippi PSC on March 7, 2001, and resulted in a slight increase in customer
prices. The Company filed its 2002 ECO Plan in January 2002, which, if approved
as filed, will result in a slight increase in rates. See Note 3 to the financial
statements under "Litigation and Regulatory Matters" for additional information.
The Clean Air Act and other important environmental items are discussed later
under "Environmental Matters."
In August 2001, the Company filed a request with the MPSC for a retail rate
increase of approximately $46 million. In order to consider the Company's
request, the MPSC suspended the semi-annual evaluations under PEP. In December
2001, after a full investigation and hearing on the Company's request, the MPSC
approved an increase of approximately $39 million, which took effect in January
2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual
evaluations under PEP, beginning in February 2003 for the year 2002. PEP will
remain in effect until the MPSC modifies, suspends, or terminates the plan. The
MPSC also set for hearing in 2002 a review of the return on equity models used
in PEP in setting the Company's authorized return on equity. This proceeding
will conclude in 2002, so that changes to the PEP return on equity models, if
any, may be incorporated into the February 2003 PEP evaluation filing for the
period ending December 31, 2002. The outcome of this matter and any future
impact to the Company cannot now be determined.
In February 2002, the Company reached an agreement with certain of its
wholesale customers to increase its wholesale tariff rates effective June 2002.
The agreement results in an annual increase of approximately $10.5 million and
the adoption of an Energy Cost Management clause similar to the one approved by
the Company's retail jurisdiction (see Note 1 to the financials). In addition,
the Company and its customers agreed that neither party would seek a unilateral
change to the new rates prior to December 31, 2003, except for changes due to
the operation of the fuel adjustment and energy cost management clauses. The
Company and its customers will file the agreement with the FERC for its
approval. Though the FERC has accepted settlement agreements as filed in the
past, the ultimate outcome of this matter before the FERC cannot now be
determined.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash pension
income of approximately $3.2 million in 2001. Future pension income is dependent
on several factors including trust earnings and changes to the plan. For the
Company, pension income is a component of the regulated rates and does not have
a significant effect on net income. For more information, see Note 2 to the
financial statements.
The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. The Clean Air Act and other important environmental items are
discussed later under "Environmental Matters."
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. These factors include weather,
competition, changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, and the rate of
economic growth in the Company's service area. The Company anticipates somewhat
slower growth in energy sales as the tourism industry stabilizes within its
service area. In addition to tourism, the healthcare and retail trade sectors
will provide most of the anticipated energy growth for the commercial class of
customers, while shipbuilding, chemicals, and the U.S. government will provide
much of the basis for anticipated growth in the industrial sector.
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are affected by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
various 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 could radically
change. In May 2000, the MPSC ordered that its docket reviewing restructuring of
the electric industry in the State of Mississippi be suspended. The MPSC found
that retail competition may not be in the public interest at this time, and
ordered that no further formal hearings would be held on this subject. It found
that the current regulatory structure produced reliable low cost power and
"should not be changed without clear and convincing demonstration that change
would be in the public interest." The MPSC will continue to monitor retail and
wholesale restructuring activities throughout the United States and reserves its
right to order further formal hearings on the matter should new evidence
demonstrate that retail competition would be in the public interest and all
customers could receive a reduction in the total cost of their electric service.
If the MPSC decides to hold future restructuring hearings on this matter,
enactment would require numerous issues to be resolved, including significant
ones relating to recovery of any stranded investments, full cost recovery of
energy produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation.
Continuing to be a low-cost producer could provide significant opportunities
to increase market share and profitability in markets that evolve with changing
regulation. Conversely, unless the Company remains a low-cost producer and
provides quality service, the Company's energy sales growth could be limited,
and this could significantly erode earnings.
In December 1999, the FERC issued its final ruling on Regional Transmission
Organizations (RTOs). The order encourages utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company and its operating companies,
including the Company, have submitted a series of status reports informing the
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing a for-profit RTO known
as SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. While the creation of SeTrans is not
expected to have a material impact on the Company's financial statements, the
outcome of this matter cannot now be determined.
II-153
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
Accounting Policies
Critical Policies
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operation is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
Additionally, the Company accounts for its lease agreement with Escatawpa
Funding, Limited Partnership (Escatawpa) as an operating lease. Under this
agreement, Escatawpa, a special purpose entity, is owner-lessor of the
combined-cycle generating units at the Company's Plant Daniel. The Company does
not consolidate this entity since parties unrelated to the Company have made
substantive residual equity capital investments in excess of 3 percent. The FASB
has recently issued a draft interpretation that addresses issues related to
identifying and accounting for certain special purpose entities. One proposed
change would increase the 3 percent outside equity requirement to 10 percent.
This interpretation is in draft form; therefore, final conclusions may differ
from the draft. However, a change to a ten percent equity requirement could
result in the Company having to change its accounting for this lease agreement,
including having to consolidate the leased asset and related debt. See Note 4 to
the financial statements where the lease agreement and the Company's related
obligations are discussed.
New Accounting Standards
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on the Company's net income in 2001 was not material. An
additional interpretation of Statement No. 133 will result in a change -
effective April 1, 2002 - in accounting for certain contracts related to fuel
supplies that contain quantity options. These contracts will be accounted for as
derivatives and marked to market. However, due to the existence of the Company's
cost-based fuel recovery clause, this change is not expected to have a material
impact on net income.
In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No.142 in January 2002 with no material
impact on the financial statements.
Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition during 2001 was the
addition of approximately $61 million to utility plant. Funding for these
II-154
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
additions and other capital requirements were derived primarily from operations.
The Statements of Cash Flows provide additional details.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are certain fixed-price physical gas purchase contracts that
could require collateral - but not accelerated payment - in the event of a
credit rating change to below investment grade; however, at December 31, 2001,
this exposure was immaterial.
Exposure to Market Risks
Due to cost-based rate regulations, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To 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 statements as incurred. At December 31, 2001,
exposure from these activities was not material to the Company's financial
statements. Also, based on the Company's overall variable rate long-term debt
exposure at December 31, 2001, a near-term 100 basis point change in interest
rates would not materially affect the Company's financial statements. Fair value
of changes in energy trading contracts and year-end valuations are as follows:
Changes
During the Year
----------------------
Fair Value
----------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 112
Contracts realized or settled (101)
New contracts at inception -
Changes in valuation techniques -
Current period changes (3,841)
- -----------------------------------------------------------------
Contracts end of year $ (3,830)
=================================================================
Source of Year-End
Valuation Prices
-----------------------------------
Maturity
Total --------------------
Fair Value Year 1 1-3 Years
- -----------------------------------------------------------------
(in thousands)
- -----------------------------------------------------------------
Actively quoted $(3,830) $(3,517) $ (313)
External sources - - -
Models and other methods
- - -
- -----------------------------------------------------------------
Contracts end of year $(3,830) $(3,517) $ (313)
=================================================================
For additional information, see Note 1 to the financial statements under
"Financial Instruments."
In June 2001, the MPSC approved the Company's request to implement an Energy
Cost Management Clause (ECM). ECM, among other things, allows the Company to
utilize financial instruments to hedge its fuel commitments. Amounts paid or
received as a result of the use of these instruments are recognized as fuel
related expense and are recovered or credited through the ECM factor calculated
annually and applied to customer billings. The Company records the fair value of
these financial instruments (cash flow hedges) in its financial statements in
accordance with FASB Statement No. 133 with a related regulatory asset or
liability recorded under the provisions of FASB Statement No. 71.
As of December 31, 2001, the Company had financial instruments related to
natural gas commodity contracts that had a contract value of approximately $31
million and $30 million expiring in 2002 and 2003, respectively. The market
values as of December 31, 2001 for these contracts were approximately $27
million and $30 million, respectively. The amounts settled and recognized in the
financial statements for 2001 were not material. Currently, the Company does not
have any fixed price natural gas commitments, either physical or financial,
beyond 2003.
Sources of Capital
To meet short-term cash needs and contingencies, the Company had at December 31,
2001 approximately $18.9 million of cash and cash equivalents and approximately
$114.5 million of unused committed credit agreements.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
II-155
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
At December 31, 2001, the Company had outstanding $16 million of commercial
paper.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from sources similar to those used in the past. These sources were primarily the
issuance of first mortgage bonds and preferred securities, in addition to
pollution control revenue bonds issued for the Company's benefit by public
authorities. The Company also utilized unsecured debt and lease arrangements in
the past as well.
The Company has no restrictions on the amounts of unsecured indebtedness it
may incur. However, the Company is required to meet certain coverage
requirements specified in its mortgage indenture and corporate charter to issue
new first mortgage bonds and preferred stock. The Company's coverage ratios are
high enough to permit, at present interest rate levels, any foreseeable security
sales. The amount of securities which the Company will be permitted to issue in
the future will depend upon market conditions and other factors prevailing at
that time.
Financing Activity
In May 2001, the Company received a $70 million capital contribution which was
used to retire $35 million of 6.60 percent first mortgage bonds, $20 million of
series C variable-rate senior notes, and $15 million in short term debt. The
Company plans to continue, to the extent possible, a program to retire
higher-cost debt and replace these securities with lower-cost capital. See the
Statements of Cash Flows for further details.
Composite financing rates decreased for the year 2001 when compared to 2000
and 1999. As of year-end, the composite rates were as follows:
2001 2000 1999
-------------------------------
Composite interest rate on
long-term debt 4.60% 6.41% 6.19%
Composite preferred stock
dividend rate 6.33% 6.33% 6.33%
Composite interest rate on
preferred securities 7.75% 7.75% 7.75%
--------------------------------------------------------------
Off-Balance Sheet Financing Arrangements
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with
Escatawpa. These agreements called for the Company to design and construct, as
agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility at the
Company's Plant Victor J. Daniel Facility (Facility). In May 2001, the Facility
was completed and placed into commercial operation. Effective with commercial
operation of the Facility, the initial 10-year lease term under its lease
arrangement for the Facility with Escatawpa began. The completion cost was
approximately $370 million. The lease provides for a residual value guarantee
(approximately 71% of the completion cost) by the Company that is due upon
termination of the lease in certain circumstances. The lease also includes
purchase and renewal options. Upon termination of the lease, at the Company's
option, the Company may either exercise its purchase option or the Facility can
be sold to a third party. The Company expects that the fair market value of the
leased Facility would substantially reduce or eliminate the Company's payment
under the residual value guarantee. In 2001, the Company recognized
approximately $18 million in lease expense. See Note 4 to the financial
statements for additional information.
Capital Structure
At year-end 2001, the Company's ratio of common equity to total capitalization,
excluding long-term debt due within one year, increased from 48.1 percent in
2000 to 62.1 percent. The Company plans to replace the long-term debt due within
one year with new issues.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$241 million ($84 million in 2002, $72 million in 2003, and $85 million in
2004). The major emphasis within the construction program will be on the upgrade
of existing facilities.
Revisions to projected construction expenditures may be necessary because of
factors such as changes in business conditions, revised load projections, the
availability and cost of capital, changes in environmental regulations, and
alternatives such as leasing.
II-156
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $115 million will be required by the end of 2003 for present
sinking fund requirements and maturities of long-term debt. The Company plans to
continue, when economically feasible, to retire higher cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
These capital requirements, lease obligations, and purchase commitments -
discussed in notes 4 and 8 to the financial statements - are as follows:
2002 2003 2004
----------------------------------------------------------
(in thousands)
Bonds -
First mortgage $ - $ - $ -
Pollution control 20 25 25
Notes 80,000 35,000 -
Lease obligations 27,000 27,000 27,000
Purchase commitments
Fuel 225,000 188,000 7,000
Purchased power - - -
- -----------------------------------------------------------
At the beginning of 2002, the Company had not used any of its available
credit arrangements. Credit arrangements are as follows:
Expires
-----------------------------
Total Unused 2002 2003 & Beyond
- ------------------------------------------------------------
(in millions)
$114.5 $114.5 $109.5 5.0
- ------------------------------------------------------------
Environmental Matters
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action in the U.S. District Court against Alabama Power Company, Georgia Power
Company, and the system service company. The complaint alleges violations of the
New Source Review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the operating companies a notice of violation related
to 10 generating facilities, which includes the five facilities mentioned
previously, and the Company's plants Watson and Greene County. In early 2000,
the EPA filed a motion to amend its complaint to add the violations alleged in
its notice of violation, and to add Gulf Power, Savannah Electric, and the
Company as defendants. The complaint and notice of violation are similar to
those brought against and issued to several other electric utilities. These
complaints and notices of violation allege that the utilities had failed to
secure necessary permits or install additional pollution control equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. The U.S. District Court in Georgia granted
Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and
granted the system service company's motion to dismiss on the grounds that it
neither owned nor operated the generating units involved in the proceedings. The
court granted the EPA's motion to add Savannah Electric as a defendant, but it
denied the motion to add Gulf Power and the Company based on lack of
jurisdiction over those companies. The court directed the EPA to re-file its
amended complaint limiting claims to those brought against Georgia Power and
Savannah Electric. The EPA re-filed those claims as directed by the court. Also,
the EPA re-filed its claims against Alabama Power in U.S. District Court in
Alabama. It has not re-filed against Gulf Power, the system service company, or
the Company.
The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
$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 unless such costs can be
recovered through regulated rates.
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company. Reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
were required in two phases. Phase I compliance began in 1995.
Southern Company achieved Phase I compliance at its affected plants by
primarily switching to low-sulfur coal and with some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $65 million for the Company.
Phase II sulfur dioxide compliance was required in 2000. Southern Company
used emission allowances and fuel switching to comply with Phase II
requirements. Also, equipment to control nitrogen oxide emissions was installed
on additional system fossil-fired units as necessary to meet Phase II limits and
ozone non-attainment requirements for metropolitan Atlanta through 2000. Phase
II compliance did not have a material impact on the Company.
The Company's ECO Plan is designed to allow recovery of costs of compliance
with the Clean Air Act, as well as other environmental statutes and regulations.
The MPSC reviews environmental projects and the Company's environmental policy
through the ECO Plan. Under the ECO Plan, any increase in the annual revenue
requirement is limited to 2 percent of retail revenues. The Company's management
believes that the ECO Plan provides for recovery of the Clean Air Act costs. See
Note 3 to the financial statements under "Environmental Compliance Overview
Plan" for additional information.
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and fine particulate matter. This revision made the standards
significantly more stringent. In the subsequent litigation of these standards,
the U.S. Supreme Court found the EPA's implementation program for the new ozone
standard unlawful and remanded it to the EPA. In addition, the Federal District
of Columbia Circuit Court of Appeals is considering other legal challenges to
these standards. A court decision is expected in the spring of 2002. If the
standards are eventually upheld, implementation could be required by 2007 to
2010.
In September 1998, the EPA issued regional nitrogen oxide reduction rules to
the states for implementation. Compliance is required by May 31, 2004 for most
states including Alabama. For Georgia, further rulemaking was required, and
proposed compliance was delayed until May 1, 2005. The final rules affect 21
states that do not include Mississippi. The EPA is presently evaluating whether
or not to bring an additional 15 states including Mississippi, under this
regional nitrogen oxide rule.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and the regulations are scheduled to be finalized by the end
of 2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place in 2010. Litigation of the Regional Haze
Regulations, including the BART provisions, is ongoing in the Federal District
of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. Upon identifying potential sites, the Company conducts
studies, when possible, to determine the extent of any required cleanup. Should
remediation be determined to be probable, reasonable estimates of costs to clean
up such sites are developed and recognized in the financial statements.
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; and the Endangered
Species Act. Changes to these laws could affect many areas of the Company's
operations. The full impact of any such changes cannot be determined at this
time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if any
- -- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
Cautionary Statement Regarding Forward-Looking
Information
This Annual Report includes forward-looking statements in addition to historical
information. Forward-looking information includes, among other things,
statements concerning projected sales growth and scheduled completion of new
generation. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
"anticipates," "believes," "estimates," "predicts," "projects," "potential," or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action against the Company; the effects, extent and timing of the entry of
additional competition in the markets of the Company; the impact of fluctuations
in commodity prices, interest rates, and customer demand; state and federal rate
regulations; political, legal, and economic conditions and developments in the
United States; internal restructuring or other restructuring options that may be
pursued; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or beneficial
to the Company; the effects of, and changes in, economic conditions in the areas
in which the Company operates; the direct or indirect effects on the Company's
business resulting from the terrorist incidents on September 11, 2001, or any
similar such incidents or responses to such incidents; financial market
conditions and the results of financing efforts; the timing and acceptance of
the Company's new product and service offerings; the ability of the Company to
obtain additional generating capacity at competitive prices; weather and other
natural phenomena; and other factors discussed elsewhere herein and in other
reports (including Form 10-K) filed from time to time by the Company with the
Securities and Exchange Commission.
II-159
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Mississippi Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------
2001 2000 1999
- --------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $489,153 $498,551 $469,434
Sales for resale --
Non-affiliates 204,623 145,931 131,004
Affiliates 85,652 27,915 19,446
Other revenues 16,637 15,205 13,120
- --------------------------------------------------------------------------------------------------------------
Total operating revenues 796,065 687,602 633,004
- --------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 277,946 191,127 172,686
Purchased power --
Non-affiliates 41,254 56,082 40,080
Affiliates 53,990 51,057 31,007
Other 134,845 115,055 125,291
Maintenance 56,153 52,750 47,085
Depreciation and amortization 54,077 50,275 49,206
Taxes other than income taxes 44,966 48,686 47,893
- --------------------------------------------------------------------------------------------------------------
Total operating expenses 663,231 565,032 513,248
- --------------------------------------------------------------------------------------------------------------
Operating Income 132,834 122,570 119,756
Other Income (Expense):
Interest income 369 347 189
Other, net (532) (647) 1,675
- --------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 132,671 122,270 121,620
- --------------------------------------------------------------------------------------------------------------
Interest Expense and Other:
Interest expense, net 23,568 28,101 27,969
Distributions on preferred securities of subsidiary 2,712 2,712 2,712
- --------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 26,280 30,813 30,681
- --------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 106,391 91,457 90,939
Income taxes 40,533 34,356 34,117
- --------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 65,858 57,101 56,822
Accounting Change
Cumulative effect of accounting change--
less income taxes of $43 thousand 70 - -
- --------------------------------------------------------------------------------------------------------------
Net Income 65,928 57,101 56,822
Dividends on Preferred Stock 2,041 2,129 2,013
- --------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 63,887 $ 54,972 $ 54,809
==============================================================================================================
The accompanying notes are an integral part of these statements.
II-160
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Mississippi Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 65,928 $ 57,101 $ 56,822
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 58,105 54,638 53,427
Deferred income taxes and investment tax credits, net (9,718) 752 (4,143)
Other, net 2,441 (1,747) 5,531
Changes in certain current assets and liabilities --
Receivables, net (7,796) (3,231) (39,304)
Fossil fuel stock (20,269) 14,577 (9,379)
Materials and supplies (1,529) (1,056) (1,903)
Accounts payable 53,462 1,309 1,391
Other 11,251 2,952 14,206
- -----------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 151,875 125,295 76,648
- -----------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (61,193) (81,211) (75,888)
Other (2,988) (9,153) 1,009
- -----------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (64,181) (90,364) (74,879)
- -----------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (40,027) (1,500) 44,500
Proceeds --
Other long-term debt - 100,000 59,400
Capital contributions from parent company 73,095 12,659 2,028
Retirements --
First mortgage bonds (36,000) - -
Other long-term debt (21,021) (81,405) (50,456)
Preferred stock - - -
Payment of preferred stock dividends (2,041) (2,129) (2,013)
Payment of common stock dividends (50,200) (54,700) (56,100)
Other (81) (498) (282)
- -----------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (76,275) (27,573) (2,923)
- -----------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 11,419 7,358 (1,154)
Cash and Cash Equivalents at Beginning of Period 7,531 173 1,327
- -----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 18,950 $ 7,531 $173
=======================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $28,126 $30,570 $25,486
Income taxes (net of refunds) 45,761 33,276 39,729
- -----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-161
BALANCE SHEETS
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- -------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 18,950 $ 7,531
Receivables --
Customer accounts receivable 63,286 72,064
Other accounts and notes receivable 26,068 21,843
Affiliated companies 22,569 10,071
Accumulated provision for uncollectible accounts (856) (571)
Fossil fuel stock, at average cost 31,489 11,220
Materials and supplies, at average cost 23,223 21,694
Other 16,002 8,320
- -------------------------------------------------------------------------------------------------------------------------
Total current assets 200,731 152,172
- -------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,741,499 1,665,879
Less accumulated provision for depreciation 698,681 652,891
- -------------------------------------------------------------------------------------------------------------------------
1,042,818 1,012,988
Construction work in progress 38,253 60,951
- -------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,081,071 1,073,939
- -------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 1,900 2,268
- -------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 13,394 13,860
Prepaid pension costs 4,501 434
Debt expense, being amortized 4,396 4,628
Premium on reacquired debt, being amortized 6,719 7,168
Other 20,821 14,312
- -------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 49,831 40,402
- -------------------------------------------------------------------------------------------------------------------------
Total Assets $1,333,533 $1,268,781
=========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-162
BALANCE SHEETS
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2001 2000
- -----------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 80,020 $ 20
Notes payable 15,973 56,000
Accounts payable --
Affiliated 6,175 10,715
Other 105,834 48,146
Customer deposits 6,540 5,274
Taxes accrued --
Income taxes 14,981 8,769
Other 35,282 36,799
Interest accrued 5,079 4,482
Vacation pay accrued 5,810 5,701
Other 11,483 6,473
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 287,177 182,379
- -----------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 233,753 370,511
- -----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 138,913 139,909
Deferred credits related to income taxes 23,626 25,603
Accumulated deferred investment tax credits 22,268 23,481
Employee benefits provisions 31,041 28,911
Workforce reduction plan 8,263 9,734
Other 30,003 16,546
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 254,114 244,184
- -----------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding company junior
subordinated notes (See accompanying statements) 35,000 35,000
- -----------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 31,809 31,809
- -----------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 491,680 404,898
- -----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,333,533 $1,268,781
=======================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-163
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- -------------
June 1, 2023 7.45% $ 34,000 $ 35,000
March 1, 2004 6.60% - 35,000
December 1, 2025 6.875% 30,000 30,000
- -----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 64,000 100,000
- -----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.05% due May 1, 2003 35,000 35,000
6.75% due June 30, 2038 52,178 53,179
Adjustable rates (2.0056% at 1/1/02)
due 2000-2002 80,000 100,000
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 167,178 188,179
- -----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.65% to 5.80% due 2007-2023 26,745 26,765
Non-collateralized:
Variable rates (1.90% to 2.00% at 1/1/02)
due 2020-2028 56,820 56,820
- -----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 83,565 83,585
- -----------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (970) (1,233)
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $14.5 million) 313,773 370,531
Less amount due within one year 80,020 20
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $233,753 $370,511 29.5% 43.9%
- -----------------------------------------------------------------------------------------------------------------------------
II-164
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities:(Note 8)
$25 liquidation value --
7.75% $ 35,000 $ 35,000
- -----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million) 35,000 35,000 4.4 4.2
- -----------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value
4.40% to 7.00% 31,809 31,809
- -----------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $2.0 million) 31,809 31,809 4.0 3.8
- -----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares in 2001 and 2000 37,691 37,691
Paid-in capital 267,256 194,161
Premium on preferred stock 326 326
Retained earnings 186,407 172,720
- -----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 491,680 404,898 62.1 48.1
- -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $792,242 $842,218 100.0% 100.0%
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-165
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Mississippi Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1999 $37,691 $179,474 $326 $173,740 $391,231
Net income after dividends on preferred stock - - - 54,809 54,809
Capital contributions from parent company - 2,028 - - 2,028
Cash dividends on common stock - - - (56,100) (56,100)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 37,691 181,502 326 172,449 391,968
Net income after dividends on preferred stock - - - 54,972 54,972
Capital contributions from parent company - 12,659 - - 12,659
Cash dividends on common stock - - - (54,700) (54,700)
Other - - - (1) (1)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 37,691 194,161 326 172,720 404,898
Net income after dividends on preferred stock - - - 63,887 63,887
Capital contributions from parent company - 73,095 - - 73,095
Cash dividends on common stock - - - (50,200) (50,200)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $37,691 $267,256 $326 $186,407 $491,680
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-166
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2001 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Mississippi Power Company is a wholly owned subsidiary of Southern Company,
which is the parent company of five operating companies, a system service
company, Southern Communications Services (Southern LINC), Southern Nuclear
Operating Company (Southern Nuclear), Southern Power Company (Southern Power),
and other direct and indirect subsidiaries. The operating companies -- Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company, and Savannah Electric and Power Company -- provide electric service in
four southeastern states. Contracts among the operating companies -- related to
jointly owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission. The system
service company provides, at cost, specialized services to Southern Company and
subsidiary companies. Southern LINC provides digital wireless communications
services to the operating companies and also markets these services to the
public within the Southeast. Southern Nuclear provides services to Southern
Company's nuclear power plants. Southern Power was established in 2001 to
construct, own, and manage Southern Company's competitive generation assets and
sell electricity at market-based rates in the wholesale market.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both the 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 Mississippi Public Service Commission (MPSC).
The Company follows accounting principles generally accepted in the United
States and complies with the accounting policies and practices prescribed by the
respective commissions. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the
use of estimates, and the actual results may differ from those estimates.
Prior years' data presented in the financial statements have been
reclassified to conform with the current year presentation.
Affiliate Transactions
The Company has an agreement with the system service company under which the
following services are rendered to the Company at cost: general and design
engineering, purchasing, accounting and statistical, finance and treasury, tax,
information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures, and other services with
respect to business and operations and power pool operations. Costs for these
services amounted to $44.1 million, $46.2 million, and $45.5 million during
2001, 2000, and 1999, 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. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:
2001 2000
-------------------------
(in thousands)
Deferred income tax charges $ 13,394 $ 13,860
Vacation pay 5,810 5,701
Premium on reacquired debt 6,719 7,168
Fuel commitments 4,328 -
Property damage reserve (4,044) (3,519)
Deferred income tax credits (23,626) (25,603)
Other, net (1,066) (505)
- ----------------------------------------------------------------
Total $ 1,515 $ (2,898)
================================================================
II-167
NOTES (continued)
Mississippi Power Company 2001 Annual Report
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 value.
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 Mississippi and to wholesale customers in the Southeast.
Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. The Company's retail and wholesale
rates include provisions to adjust billings for fluctuations in fuel costs, the
energy component of purchased power costs, and certain other costs. Retail rates
also include provisions to adjust billings for fluctuations in costs for ad
valorem taxes, certain qualifying environmental costs, and energy cost
management activities. Revenues are adjusted for differences between actual
allowable amounts and the amounts included in 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 continued to average less than 1 percent of revenues.
Depreciation
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.5 percent in 2001, 3.5
percent in 2000, and 3.3 percent in 1999. When property subject to depreciation
is retired or otherwise disposed of in the normal course of business, its
original cost -- together with the cost of removal, less salvage -- is charged
to accumulated depreciation. 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 removal of
facilities.
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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction, if
applicable. The cost of maintenance, repairs, and replacement of minor items of
property is charged to maintenance expense except for the maintenance of coal
cars and a portion of the railway track maintenance, which are charged to fuel
stock. The cost of replacements of property -- exclusive of minor items of
property -- is capitalized.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Financial Instruments
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The 2001 impact
on net income was immaterial. The Company uses derivative financial instruments
to hedge exposure to fluctuations in interest rates and certain commodity
prices. Gains and losses on qualifying hedges are deferred and recognized either
as income or as an adjustment to the carrying amount of the hedged item when the
transaction occurs. The Company is exposed to losses related to financial
instruments in the event of counterparties' nonperformance. The Company has
established controls to determine and monitor the creditworthiness of
counterparties in order to mitigate the Company's exposure to counterparty
credit risk.
The Company and its affiliates, through the system service company acting as
their agent, enters into commodity related forward and option contracts to limit
II-168
NOTES (continued)
Mississippi Power Company 2001 Annual Report
exposure to changing prices on certain fuel purchases and electricity purchases
and sales. Substantially all of these bulk energy purchases and sales contracts
meet the definition of a derivative under FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities. In many cases, these fuel and
electricity contracts qualify for normal purchase and sale exceptions under
Statement No. 133 and are accounted for under the accrual method. Other
contracts qualify as cash flow hedges of anticipated transactions, resulting in
the deferral of related gains and losses, and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.
In June 2001, the MPSC approved the Company's request to implement an Energy
Cost Management Clause (ECM). ECM, among other things, allows the Company to
utilize financial instruments that are used to hedge its fuel commitments.
Amounts paid or received as a result of financial settlement of these
instruments are classified as fuel expense and are included in the ECM factor
applied to customer billings. The Company records the fair value of these
financial instruments (cash flow hedges) in its financial statements in
accordance with FASB Statement No. 133 with a related regulatory asset or
liability recorded under the provisions of FASB Statement No. 71.
As of December 31, 2001, the Company had financial instruments related to
natural gas commodity contracts that had a contract value of approximately $31
million and $30 million expiring in 2002 and 2003, respectively. The market
values as of December 31, 2001 for these contracts were approximately $27
million and $30 million, respectively. The amounts settled and recognized in the
financial statements for 2001 were not material. Currently, the Company does not
have any fixed price natural gas commitments, either physical or financial,
beyond 2003.
The Company's other financial instruments for which the carrying amount did
not equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
------------------------
(in millions)
Long-term debt:
At December 31, 2001 $314 $309
At December 31, 2000 $371 $362
Capital trust preferred
securities:
At December 31, 2001 $ 35 $ 35
At December 31, 2000 $ 35 $ 34
- -----------------------------------------------------------
The fair values for long-term debt and preferred securities were based on
either closing market price or closing price of comparable instruments.
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
used or installed.
Provision for Property Damage
The Company is self-insured for the cost of storm, fire, and other uninsured
casualty damage to its property, including transmission and distribution
facilities. As permitted by regulatory authorities, the Company accrues for the
cost of such damage by charging expense and crediting an accumulated provision.
The cost of repairing damage resulting from such events that individually exceed
$50 thousand is charged to the accumulated provision. In 1999, an order from the
MPSC increased the maximum Property Damage Reserve from $18 million to $23
million and allows an annual accrual of up to $4.6 million. In 2001, the Company
provided for such costs by charges to income of $2.5 million. In 2000 and 1999,
the Company provided for such costs by charges to income of $3.5 million and
$4.4 million, respectively. As of December 31, 2001, the accumulated provision
amounted to $4.0 million.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all these employees may
become eligible for such benefits when they retire. The Company funds trusts to
II-169
NOTES (continued)
Mississippi Power Company 2001 Annual Report
the extent deductible under federal income tax regulations or the extent
required by regulatory authorities. In late 2000, the Company adopted several
pension and postretirement benefits plan changes that had the effect of
increasing benefits to both current and future retirees. The measurement date
for plan assets and obligations is September 30 for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
--------------------------
2001 2000
- ---------------------------------------------------------------------
(in thousands)
Balance at beginning of year $154,411 $148,657
Service cost 4,797 4,357
Interest cost 11,817 10,912
Benefits paid (8,456) (8,169)
Actuarial gain and employee
transfers 1,268 (1,646)
Amendments 8,406 300
Other (76) -
- ---------------------------------------------------------------------
Balance at end of year $172,167 $154,411
=====================================================================
Plan Assets
--------------------------
2001 2000
- ---------------------------------------------------------------------
(in thousands)
Balance at beginning of year $256,648 $221,487
Actual return on plan assets (37,214) 39,737
Benefits paid (7,850) (7,593)
Employee transfers (38) 3,017
- ---------------------------------------------------------------------
Balance at end of year $211,546 $256,648
=====================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2001 2000
- ---------------------------------------------------------------------
(in thousands)
Funded status $ 39,379 $ 102,238
Unrecognized transition obligation (2,716) (3,253)
Unrecognized prior service cost 13,656 6,298
Unrecognized net gain (45,818) (104,849)
- ---------------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 4,501 $ 434
=====================================================================
Components of the pension plans' net periodic cost were as follows:
2001 2000 1999
- ---------------------------------------------------------------
(in thousands)
Service Cost $ 4,797 $ 4,357 $ 4,501
Interest cost 11,818 10,912 10,025
Expected return on
plan assets (17,328) (15,910) (14,681)
Recognized net gain (3,012) (2,577) (1,670)
Net amortization 511 76 76
- ---------------------------------------------------------------
Net pension income $ (3,214) $ (3,142) $ (1,749)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
---------------------------
2001 2000
- ----------------------------------------------------------------
(in thousands)
Balance at beginning of year $44,952 $45,390
Service cost 922 830
Interest cost 3,411 3,309
Benefits paid (2,918) (2,628)
Actuarial gain and
employee transfers 3,256 (1,949)
Amendments 1,900 -
----------------------------------------------------------------
Balance at end of year $51,523 $44,952
================================================================
Plan Assets
---------------------------
2001 2000
- ----------------------------------------------------------------
(in thousands)
Balance at beginning of year $17,843 $14,998
Actual return on plan assets (1,888) 2,511
Employer contributions 3,232 2,961
Benefits paid (2,918) (2,627)
- ----------------------------------------------------------------
Balance at end of year $16,269 $17,843
================================================================
II-170
NOTES (continued)
Mississippi Power Company 2001 Annual Report
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2001 2000
- ------------------------------------------------------------------
(in thousands)
Funded status $(35,254) $(27,109)
Unrecognized transition obligation 3,928 4,275
Unrecognized prior service cost 1,821 -
Unrecognized net gain (40) (6,632)
Fourth quarter contributions 1,268 1,065
- ------------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(28,277) $(28,401)
==================================================================
Components of the postretirement plans' net periodic cost
were as follows:
2001 2000 1999
- ------------------------------------------------------------------
(in thousands)
Service cost $ 922 $ 830 $ 981
Interest cost 3,411 3,309 3,105
Expected return on
plan assets (1,409) (1,235) $(1,100)
Transition obligation 346 346 346
Prior service cost 80 - -
Recognized net loss (38) - -
- ------------------------------------------------------------------
Net postretirement cost $ 3,312 $ 3,250 $ 3,332
==================================================================
The weighted average rates assumed in the actuarial calculations
for both the pension plans and postretirement benefits plan were:
2001 2000
---------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Long-term return on plan assets 8.50 8.50
---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010 and
remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:
1 Percent 1 Percent
Increase Decrease
- -----------------------------------------------------------------
(in thousands)
Benefit obligation $4,037 $3,551
Service and interest costs 314 273
- -----------------------------------------------------------------
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $2.5
million, $2.3 million, and $2.2 million, respectively.
3. LITIGATION AND REGULATORY MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power and the system service company. The complaint alleges violations of the
New Source Review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day.
The EPA concurrently issued to the operating companies a notice of
violation related to 10 generating facilities, which includes the five
facilities mentioned previously, and the Company's plants Watson and Greene
County. In early 2000, the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation and to add Gulf Power, Savannah
II-171
NOTES (continued)
Mississippi Power Company 2001 Annual Report
Electric and the Company as defendants. The complaint and notice of violation
are similar to those brought against and issued to several other electric
utilities. These complaints and notices of violation allege that the utilities
had failed to secure necessary permits or install additional pollution control
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. The U.S. District Court in
Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction and
granted the system service company's motion to dismiss on the grounds that it
neither owned nor operated the generating units involved in the proceedings. The
court granted the EPA's motion to add Savannah Electric as a defendant, but it
denied the motion to add Gulf Power and the Company based on lack of
jurisdiction over those companies. The court directed the EPA to re-file its
amended complaint limiting claims to those brought against Georgia Power and
Savannah Electric. The EPA re-filed those claims as directed by the court. Also,
the EPA re-filed its claims against Alabama Power in U.S. District Court in
Alabama. It has not re-filed against Gulf Power, the system service company, or
the Company.
The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.
The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and could possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates.
Retail Rate Adjustment Plans
The Company's retail base rates are set under a Performance Evaluation Plan
(PEP) approved by the MPSC in 1994. PEP was designed with the objective that the
plan would reduce the impact of rate changes on the customer and provide
incentives for the Company to keep customer prices low. PEP includes a mechanism
for rate adjustments based on the Company's ability to maintain low rates for
customers and on the Company's performance as measured by three indicators that
emphasize price and service to the customer. PEP provides for semiannual
evaluations of the Company's performance-based return on investment. Any change
in rates is limited to 2 percent of retail revenues per evaluation period.
In August 2001, the Company filed a request with the MPSC for a retail rate
increase of approximately $46 million. In order to consider the Company's
request, the MPSC suspended the semi-annual evaluations under PEP. In December
2001, after a full investigation and hearing on the Company's request, the MPSC
approved an increase of approximately $39 million, which took effect in January
2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual
evaluations under PEP, beginning in February 2003 for the year 2002. PEP will
remain in effect until the MPSC modifies, suspends, or terminates the plan. The
MPSC also set for hearing in 2002 a review of the return on equity models used
in PEP in setting the Company's authorized return on equity. This proceeding
will conclude in 2002, so that changes to the PEP return on equity models, if
any, may be incorporated into the February 2003 PEP evaluation filing for the
period ending December 31, 2002. The outcome of this matter and any future
impact to the Company cannot now be determined.
Environmental Compliance Overview Plan
The MPSC approved the Company's Environmental Compliance Overview Plan (ECO
Plan) in 1992. The ECO Plan establishes procedures to facilitate the MPSC's
overview of the Company's environmental strategy and provides for recovery of
costs (including costs of capital) associated with environmental projects
approved by the MPSC. Under the ECO Plan, any increase in the annual revenue
II-172
NOTES (continued)
Mississippi Power Company 2001 Annual Report
requirement is limited to 2 percent of retail revenues. However, the ECO Plan
also provides for carryover of any amount over the 2 percent limit into the next
year's revenue requirement. The Company conducts studies, when possible, to
determine the extent of any required environmental remediation. Should such
remediation be determined to be probable, reasonable estimates of costs to clean
up such sites are developed and recognized in the financial statements. The
Company recovers such costs under the ECO Plan as they are incurred, as provided
for in the Company's 1995 ECO Plan Order. The Company filed its 2002 ECO Plan in
January, which, if approved as filed, will result in a slight increase in
customer prices.
Approval for New Capacity
In January 1998, the Company was granted a Certificate of Public Convenience and
Necessity by the MPSC to build approximately 1,064 megawatts of combined cycle
generation at the Company's Plant Daniel site, to be placed in service by June
2001. In December 1998, the Company requested approval to transfer the ownership
rights under the certificate to Escatawpa Funding, Limited Partnership
(Escatawpa), which will lease the facility to the Company (see Note 4,
Commitments). In September 2000, the Company and the Mississippi Public
Utilities Staff entered, and the MPSC in October 2000 approved, a new
stipulation that modifies a January 1999 stipulation and order covering cost
allocation. The 1999 stipulation and MPSC order would have excluded the new
capacity from retail rate base and would have assigned the Company's existing
generating facilities entirely to the retail jurisdiction. The new stipulation
and MPSC order allocates a pro-rata share of the new capacity along with the
Company's existing generating capacity to the retail jurisdiction. The Company's
2001 retail rate case reflected this methodology and the MPSC's December 2001
order on the retail rate case filing approved the Company's cost allocations.
4. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, the costs of which
are currently estimated to total $84 million in 2002, $72 million in 2003, and
$85 million in 2004. The construction program is subject to periodic review and
revision, and actual construction costs may vary from the above estimates
because of numerous factors. These factors include changes in business
conditions; revised load growth estimates; changes in environmental regulations;
increasing costs of labor, equipment and materials; and cost of capital.
Significant construction will continue related to transmission and distribution
facilities, and the upgrading of generating plants.
Lease Agreements
In 1989, the Company entered into a twenty-two year operating lease agreement
for the use of 495 aluminum railcars. In 1994, a second lease agreement for the
use of 250 additional aluminum railcars was also entered into for twenty-two
years. The Company has the option to purchase the 745 railcars at the greater of
lease termination value or fair market value, or to renew the leases at the end
of the lease term. Both of these leases were for the transport of coal to Plant
Daniel.
Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible for
one half of the lease cost. The Company's share (50%) of the leases, charged to
fuel stock, was $1.9 million in 2001, $2.1 million in 2000, and $2.8 million in
1999. The Company's annual lease payments for 2002 through 2006 will average
approximately $2.0 million and after 2006, lease payments total in aggregate
approximately $12 million.
In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding, Limited Partnership (Escatawpa). These agreements called
for the Company to design and construct, as agent for Escatawpa, a 1,064
megawatt natural gas combined cycle facility at the Company's Plant Victor J.
Daniel Facility (Facility). In May 2001, the Facility was completed and placed
into commercial operation. Effective with commercial operation of the Facility
at Plant Daniel, the initial 10-year lease term under its lease arrangement for
the Facility with Escatawpa began. The completion cost was approximately $370
million. The lease provides for a residual value guarantee (approximately 71% of
the completion cost) by the Company that is due upon termination of the lease in
certain circumstances. The lease also includes a purchase and renewal option.
Upon termination of the lease, at the Company's option, the Company may either
exercise its purchase option or the Facility can be sold to a third party. The
Company expects that the fair market value of the leased Facility would
II-173
NOTES (continued)
Mississippi Power Company 2001 Annual Report
substantially reduce or eliminate the Company's payment under the residual value
guarantee. In 2001, the Company recognized approximately $18 million in lease
expense. The Company estimates that its annual amount of future minimum
operating lease payments, exclusive of any payment related to the residual value
guarantee, as of December 31, 2001, were as follows:
Year Lease Payments
- ---- --------------
(in millions)
2002 $26.4
2003 25.5
2004 25.2
2005 25.0
2006 24.7
2007 and thereafter 143.0
- ----------------------------------------------------------
Total commitments $269.8
==========================================================
Fuel
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
fuel. In most cases, these contracts contain provisions for price escalations,
minimum production levels, and other financial commitments. In addition, the
Company utilizes financial instruments to eliminated price volatility. Total
estimated fixed-price obligations at December 31, 2001, were as follows:
Year Fuel
- ---- ----
(in millions)
2002 $225
2003 188
2004 7
2005 7
2006 7
2007 and thereafter 86
- ----------------------------------------------------------
Total commitments $520
==========================================================
In addition, the system service company acts as agent for the five operating
companies and Southern Power with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various indices at the actual time of
delivery; therefore, only the volume commitments are firm. The Company's
committed volumes allocated based on usage projections, as of December 31, 2001
are as follows:
Year Natural Gas
- ---- -----------
(MMBtu)
2002 40,345,416
2003 39,723,953
2004 22,521,216
2005 11,161,628
2006 8,044,570
2007 and thereafter 2,981,474
- ------------------------------------------------------------
Total commitments 124,778,257
============================================================
Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.
5. JOINT OWNERSHIP AGREEMENTS
The Company and Alabama Power own as tenants in common Units 1 and 2 at Plant
Greene County located in Alabama. Additionally, the Company and Gulf Power own
as tenants in common Units 1 and 2 at Plant Daniel located in Mississippi.
At December 31, 2001, the Company's percentage ownership and investment in
these jointly owned facilities were as follows:
Company's
Generating Total Percent Gross Accumulated
Plant Capacity Ownership Investment Depreciation
----- -------- --------- ---------- ------------
(Megawatts) (in thousands)
Greene County
Units 1 and 2 500 40% $ 65,486 $ 35,116
Daniel
Units 1 and 2 1,000 50% $236,979 $116,766
--------------------------------------------------------------
The Company's share of plant operating expenses is included in the
corresponding operating expenses in the Statements of Income.
6. LONG-TERM CAPACITY SALES AND LEASE
AGREEMENTS
The Company and the other operating companies of Southern Company have long-term
contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. 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 under these agreements were not material during the periods reported.
II-174
NOTES (continued)
Mississippi Power Company 2001 Annual Report
In 1984, the Company and Entergy Corp. (formerly Gulf States Utilities)
entered into a 40-year transmission facilities agreement whereby Entergy began
paying a use fee to the Company covering all expenses relative to ownership and
operation and maintenance of a 500 kV line, including amortization of its
original $57 million cost. For the three years ended 2001, use fees collected
under this agreement, net of related expenses, amounted to approximately $2.7
million each year and are included within Other Income in the Statements of
Income.
During 2000, the Company entered into a 10-year capacity lease that began in
mid 2001. The minimum capacity lease revenue that the Company will receive will
average approximately $21 million per year over the 10-year period. Capacity
revenues for 2001 were approximately $12.3 million and were classified as sales
for resale in the financial statements.
7. INCOME TAXES
At December 31, 2001, the tax-related regulatory assets and liabilities were $13
million and $24 million, respectively. These assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized interest. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of the federal and state income tax provisions are shown below:
2001 2000 1999
----------------------------------
(in thousands)
Total provision for
income taxes
Federal --
Current $43,596 $28,934 $33,379
Deferred (8,661) 622 (3,973)
-----------------------------------------------------------------
34,935 29,556 29,406
-----------------------------------------------------------------
State --
Current 6,698 4,670 4,881
Deferred (1,057) 130 (170)
-----------------------------------------------------------------
5,641 4,800 4,711
-----------------------------------------------------------------
Total $40,576 $34,356 $34,117
=================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities are as follows:
2001 2000
-------------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $147,147 $151,278
Basis differences 8,271 8,559
Other 34,544 24,136
---------------------------------------------------------------
Total 189,962 183,973
---------------------------------------------------------------
Deferred tax assets:
Other property
basis differences 15,983 17,147
Pension and
other benefits 9,474 9,528
Property insurance 1,547 3,558
Unbilled fuel 5,596 5,727
Other 27,269 9,669
---------------------------------------------------------------
Total 59,869 45,629
---------------------------------------------------------------
Total deferred tax
liabilities, net 130,093 138,344
Portion included in current
assets, net 8,820 1,565
---------------------------------------------------------------
Accumulated deferred
income taxes in the
Balance Sheets $138,913 $139,909
===============================================================
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 $1.2 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
2001 2000 1999
--------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax, net of
federal deduction 3.4 3.4 3.4
Non-deductible book
depreciation 0.5 0.6 0.7
Other (0.8) (1.5) (1.6)
----------------------------------------------------------------
Effective income tax rate 38.1% 37.5% 37.5%
================================================================
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. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.
II-175
NOTES (continued)
Mississippi Power Company 2001 Annual Report
8. CAPITALIZATION
Preferred Securities
In February 1997, Mississippi Power Capital Trust I (Trust I), of which the
Company owns all the common securities, issued $35 million of 7.75 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust I are $36 million aggregate principal amount of the Company's 7.75 percent
junior subordinated notes due February 15, 2037.
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 Trust's payment obligations with respect to the
preferred securities.
Trust I is a subsidiary of the Company, and accordingly is consolidated in
the Company's financial statements.
Long-Term Debt Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
2001 2000
---------------------
(in thousands)
Bond improvement fund requirement $ 650 $1,000
Less: Portion to be satisfied by
certifying property additions 650 1,000
--------------------------------------------------------------
Cash sinking fund requirement - -
Current portion of other long-term debt 80,000 -
Pollution control bond cash
sinking fund requirements 20 20
--------------------------------------------------------------
Total $80,020 $ 20
==============================================================
The first mortgage bond improvement fund requirement is one percent of each
outstanding series authenticated under the indenture of the Company prior to
January 1 of each year, other than first mortgage bonds issued as collateral
security for certain pollution control obligations. The requirement must be
satisfied by June 1 of each year by depositing cash or reacquiring bonds, or by
pledging additional property equal to 166-2/3 percent of such requirement.
Bank Credit Arrangements
At December 31, 2001, the Company had total committed credit agreements with
banks for approximately $114.5 million. At year-end 2001, the unused portion of
these committed credit agreements was approximately $114.5 million. These credit
agreements expire at various dates in 2002 and 2003. Some of these agreements
allow short-term borrowings to be converted into term loans, payable in 12 equal
quarterly installments, with the first installment due at the end of the first
calendar quarter after the applicable termination date or at an earlier date at
the Company's option. In connection with these credit arrangements, the Company
agrees to pay commitment fees based on the unused portions of the commitments or
to maintain compensating balances with the banks. The amount of commercial paper
outstanding at December 31, 2001 was $16 million.
Assets Subject to Lien
The Company's mortgage indenture dated as of September 1, 1941, as amended and
supplemented, which secures the first mortgage bonds issued by the Company,
constitutes a direct first lien on substantially all of the Company's fixed
property and franchises.
Dividend Restrictions
The Company's first mortgage bond indenture and the corporate charter contain
various common stock dividend restrictions. At December 31, 2001, approximately
$118 million of retained earnings was restricted against the payment of cash
dividends on common stock under the most restrictive terms of the mortgage
indenture or corporate charter.
II-176
NOTES (continued)
Mississippi Power Company 2001 Annual Report
9. QUARTERLY FINANCIAL DATA
(UNAUDITED)
Summarized quarterly financial data for 2001 and 2000 are as follows:
Net Income
After Dividends
Operating Operating On Preferred
Quarter Ended Revenues Income Stock
- -------------------------------------------------------------------
(in thousands)
March 2001 $171,312 $23,615 $ 9,757
June 2001 203,949 32,640 16,571
September 2001 235,916 53,263 30,379
December 2001 184,888 23,315 7,180
March 2000 $134,705 $18,593 $ 6,722
June 2000 176,028 28,130 12,232
September 2000 220,119 53,943 28,762
December 2000 156,750 21,904 7,256
- -------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes.
II-177
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Mississippi Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)* $796,065 $687,602 $633,004 $595,131 $543,588
Net Income after Dividends
on Preferred Stock (in thousands) $63,887 $54,972 $54,809 $55,105 $54,010
Cash Dividends
on Common Stock (in thousands) $50,200 $54,700 $56,100 $51,700 $49,400
Return on Average Common Equity (percent) 14.25 13.80 14.00 14.15 14.00
Total Assets (in thousands) $1,333,533 $1,268,781 $1,251,136 $1,189,605 $1,166,829
Gross Property Additions (in thousands) $61,193 $81,211 $75,888 $68,231 $55,375
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $491,680 $404,898 $391,968 $391,231 $387,824
Preferred stock 31,809 31,809 31,809 31,809 31,896
Company obligated mandatorily
redeemable preferred securities 35,000 35,000 35,000 35,000 35,000
Long-term debt 233,753 370,511 321,802 292,744 291,665
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $792,242 $842,218 $780,579 $750,784 $746,385
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 62.1 48.1 50.2 52.1 52.0
Preferred stock 4.0 3.8 4.1 4.2 4.3
Company obligated mandatorily
redeemable preferred securities 4.4 4.2 4.5 4.7 4.7
Long-term debt 29.5 43.9 41.2 39.0 39.0
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's Aa3 Aa3 Aa3 Aa3 Aa3
Standard and Poor's A+ A+ AA- AA- AA-
Fitch AA- AA- AA- AA- AA-
Preferred Stock -
Moody's A3 a1 a1 a1 a1
Standard and Poor's BBB+ BBB+ A- A A
Fitch A A A A+ A+
Unsecured Long-Term Debt -
Moody's A1 - - - -
Standard and Poor's A - - - -
Fitch A+ - - - -
================================================================================================================================
Customers (year-end):
Residential 158,852 158,253 157,592 156,530 156,650
Commercial 32,538 32,372 31,837 31,319 31,667
Industrial 498 517 546 587 642
Other 173 206 202 200 200
- --------------------------------------------------------------------------------------------------------------------------------
Total 192,061 191,348 190,177 188,636 189,159
================================================================================================================================
Employees (year-end): 1,316 1,319 1,328 1,230 1,245
- --------------------------------------------------------------------------------------------------------------------------------
* 1999 data includes the true-up of the unbilled revenue estimates.
II-178
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Mississippi Power Company 2001 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)*:
Residential $ 164,716 $170,729 $159,945 $157,642 $138,608
Commercial 163,253 163,552 153,936 145,677 134,208
Industrial 156,525 159,705 151,244 135,039 140,233
Other 4,659 4,565 4,309 4,209 4,193
- ------------------------------------------------------------------------------------------------------------------------------------
Total retail 489,153 498,551 469,434 442,567 417,242
Sales for resale - non-affiliates 204,623 145,931 131,004 121,225 105,141
Sales for resale - affiliates 85,652 27,915 19,446 18,285 10,143
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 779,428 672,397 619,884 582,077 532,526
Other revenues 16,637 15,205 13,120 13,054 11,062
- ------------------------------------------------------------------------------------------------------------------------------------
Total $796,065 $687,602 $633,004 $595,131 $543,588
====================================================================================================================================
Kilowatt-Hour Sales (in thousands)*:
Residential 2,162,623 2,286,143 2,248,255 2,248,915 2,039,042
Commercial 2,840,840 2,883,197 2,847,342 2,623,276 2,407,520
Industrial 4,275,781 4,376,171 4,407,445 3,729,166 3,981,875
Other 41,009 41,153 40,091 39,772 40,508
- ------------------------------------------------------------------------------------------------------------------------------------
Total retail 9,320,253 9,586,664 9,543,133 8,641,129 8,468,945
Sales for resale - non-affiliates 5,011,212 3,674,621 3,256,175 3,157,837 2,895,182
Sales for resale - affiliates 2,952,455 452,611 539,939 552,142 478,884
- ------------------------------------------------------------------------------------------------------------------------------------
Total 17,283,920 13,713,896 13,339,247 12,351,108 11,843,011
====================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents)*:
Residential 7.62 7.47 7.11 7.01 6.80
Commercial 5.75 5.67 5.41 5.55 5.57
Industrial 3.66 3.65 3.43 3.62 3.52
Total retail 5.25 5.20 4.92 5.12 4.93
Sales for resale 3.64 4.21 3.96 3.76 3.42
Total sales 4.51 4.90 4.65 4.71 4.50
Residential Average Annual
Kilowatt-Hour Use Per Customer * 13,634 14,445 14,301 14,376 13,132
Residential Average Annual
Revenue Per Customer * $1,038.41 $1,078.76 $1,017.42 $1,007.68 $892.68
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 3,156 2,086 2,086 2,086 2,086
Maximum Peak-Hour Demand (megawatts):
Winter 2,249 2,305 2,125 1,740 1,922
Summer 2,466 2,593 2,439 2,339 2,209
Annual Load Factor (percent) 60.7 59.3 59.6 58.0 59.1
Plant Availability Fossil-Steam (percent): 92.8 92.6 91.0 90.0 92.4
- ------------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 52.0 67.8 69.4 66.5 70.5
Oil and gas 35.9 13.5 15.9 14.5 12.5
Purchased power -
From non-affiliates 3.1 7.7 6.2 8.0 3.0
From affiliates 9.0 11.0 8.5 11.0 14.0
- ------------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
====================================================================================================================================
* 1999 data includes the true-up of the unbilled revenue estimates.
II-179
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-180
MANAGEMENT'S REPORT
Savannah Electric and Power Company 2001 Annual Report
The management of Savannah Electric and Power Company has prepared--and is
responsible for--the financial statements and related information included in
this report. These statements were prepared in accordance with accounting
principles generally accepted in the United States and necessarily include
amounts that are based on the best estimates and judgments of management.
Financial information throughout this annual report is consistent with the
financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of five independent
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 the 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 Savannah Electric and Power Company in conformity with accounting principles
generally accepted in the United States.
/s/Anthony R. James
Anthony R. James
President
and Chief Executive Officer
/s/K.R. Willis
K. R. Willis
Vice President,
Treasurer, Chief Financial Officer
and Assistant Secretary
February 13, 2002
II-181
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Savannah Electric and Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Savannah Electric and Power Company (a Georgia corporation and a wholly owned
subsidiary of Southern Company) as of December 31, 2001 and 2000, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements (pages II-192 through II-206)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 2001 and
2000, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Savannah Electric and Power Company changed its method of accounting for
derivative instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-182
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Savannah Electric and Power Company 2001 Annual Report
RESULTS OF OPERATIONS
- ---------------------
Earnings
Savannah Electric and Power Company's net income for 2001 totaled $22.1 million,
representing a decrease of $0.9 million or 3.9 percent from the prior year.
Earnings were down primarily due to lower retail revenues.
In 2000, earnings were $23.0 million, representing no significant change
from the prior year.
Revenues
Total operating revenues for 2001 were $283.9 million, reflecting a 4.0 percent
decrease when compared to 2000. The following table summarizes the factors
affecting operating revenues for the past two years:
Increase (Decrease)
Amount From Prior Year
--------------------------------------
2001 2001 2000
--------------------------------------
(in thousands)
Retail --
Base Revenues $159,839 $ (1,968) $9,272
Fuel cost recovery
and other 109,333 (11,482) 31,085
-----------------------------------------------------------------
Total retail 269,172 (13,450) 40,357
-----------------------------------------------------------------
Sales for resale --
Non-affiliates 8,884 4,136 1,353
Affiliates 3,205 (1,769) 823
-----------------------------------------------------------------
Total sales for resale 12,089 2,367 2,176
-----------------------------------------------------------------
Other operating revenues 2,591 (783) 1,591
-----------------------------------------------------------------
Total operating revenues $283,852 $(11,866) $44,124
=================================================================
Percent change (4.0)% 17.5%
-----------------------------------------------------------------
Retail revenues decreased 4.8 percent or $13.5 million in 2001 as compared
to 2000. The primary contributors to the decrease were the negative impact of
mild weather on energy sales and a decrease in fuel revenues, partially due to a
lower average cost of fuel consumed.
Electric rates include provisions to adjust billings for fluctuations in
fuel costs, the energy component of purchased power costs, and certain other
costs. Under these fuel recovery provisions, fuel revenues generally equal fuel
expenses--including the fuel component of purchased energy--and do not affect
net income. However, cash flow is affected by the economic loss from
untimely recovery of these receivables. In May 2001, the Company implemented a
Fuel Cost Recovery (FCR) rate increase under a Georgia Public Service Commission
(GPSC) rate order. The order established a new fuel rate to better reflect
current fuel costs and to collect the under-recovered balance. The GPSC-approved
FCR anticipated a three year recovery of the under-recovered fuel balance. Due
to the current year decreases in fuel costs, the Company recovered approximately
70 percent of this balance by year-end 2001.
Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. These transactions do not
have a significant impact on earnings.
Sales to affiliated companies within the Southern electric system vary from
year to year depending on demand and the availability and cost of generating
resources at each company. These energy sales do not have a significant impact
on earnings.
Energy Sales
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:
KWH Percent Change
------------- -------------------
2001 2001 2000
------------- -------------------
(in millions)
Residential 1,659 (0.7)% 5.8%
Commercial 1,388 1.4 6.3
Industrial 788 (1.6) 12.2
Other 134 (1.4) 2.5
-------------
Total retail 3,969 (0.2) 7.1
Sales for resale --
Non-affiliates 111 43.4 50.3
Affiliates 88 (1.0) 15.1
-------------
Total 4,168 0.6% 7.8%
===========================================================
Total retail energy sales in 2001 decreased slightly from the prior year.
Residential sales decreased reflecting mild weather, somewhat offset by
continued growth in customers. Industrial sales decreased reflecting a slowing
of the economy. Commercial energy sales increased 1.4 percent reflecting
continued customer growth.
II-183
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
In 2000, total retail energy sales were up by 7.1 percent from the prior
year, reflecting increased energy sales of 12.2 percent to industrial customers
due to the re-opening of an industrial facility under new ownership. Residential
and commercial energy sales also increased reflecting weather related demand and
customer growth.
Expenses
Total operating expenses for 2001 were $234.3 million, a decrease of $9.0
million from the prior year due primarily to decreases in fuel expense and
purchased power from both affiliates and non-affiliates. The decrease in fuel
expense is attributable to a decrease in generation and lower fuel costs.
Purchased power decreased due principally to lower energy costs. Other operation
expense was lower reflecting decreased costs associated with discontinuation of
a marketing program and lower administrative and general expenses. Maintenance
expense increased from 2000 reflecting higher power delivery costs to support
improved customer reliability.
In 2000, total operating expenses were $243.3 million, an increase of $41.8
million from the prior year. This increase was due primarily to increases in
purchased power from both affiliates and non-affiliates and fuel expense.
Purchased power increased due principally to higher energy costs. Other
operation expense was higher reflecting increased benefit expenses. Maintenance
expense increased from 1999 reflecting higher power delivery and power
generation maintenance costs to support improved customer reliability and unit
availability, respectively. Depreciation and amortization increased reflecting
additional depreciation charges related to the GPSC accounting order. See Note 3
to the financial statements for additional information on the GPSC's 1998
accounting order.
Fuel and purchased power costs constitute the single largest expense for
the Company. The mix of energy supply is determined primarily by system load,
the unit cost of fuel consumed, and the availability of units.
The amount and sources of energy supply and the total average cost of
energy supply were as follows:
2001 2000 1999
--------------------------
Total energy supply
(millions of KWHs) 4,310 4,286 4,039
Sources of energy supply
(percent) --
Coal 50 52 45
Oil 1 2 2
Gas 3 5 10
Purchased Power 46 41 43
Total average cost of
energy supply (cents) 2.87 3.09 2.44
- -----------------------------------------------------------------
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations such as long-term debt and trust preferred securities.
Any recognition of inflation by regulatory authorities is reflected in the rate
of return allowed.
Future Earnings Potential
General
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 ranging from energy sales growth to a less regulated, more
competitive environment.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. These factors include 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 service area.
II-184
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
The Company currently operates as a vertically integrated utility providing
electricity to customers within the traditional service area of southeastern
Georgia. Prices for electricity provided by the Company to retail customers are
set by the GPSC. Prices for electricity relating to jointly owned generating
facilities, interconnecting transmission lines, and the exchange of electric
power are set by the Federal Energy Regulatory Commission (FERC).
As part of the Company's retail rate settlement in 1992, it was informally
agreed that the Company's earned rate of return on common equity should be 12.95
percent. In 1998, the GPSC issued a four-year accounting order settling its
review of the Company's earnings. See Note 3 to the financial statements for
additional information.
Southern Power Company, a new Southern Company affiliate formed in 2001 to
construct, own, and manage wholesale generating assets in the Southeast, is
currently constructing two 566 megawatt combined cycle units at Plant Wansley to
begin operation in 2002. The GPSC has certified the Company's purchase of 200
megawatts of capacity from these units to serve its retail customers for
approximately seven years.
The Company filed a base rate case on November 30, 2001 for the first time
since 1985. The primary reason for this base rate case is to recover significant
new costs related to the Plant Wansley power purchase agreement beginning June
2002, as well as other operation and maintenance expense changes. The requested
increase is 7.6 percent of total rates (base plus fuel). In the filing, the
Company announced it would file for a fuel decrease in early 2002 to offset
most, if not all, of the base rate increase.
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 under
"Environmental Matters."
Industry Restructuring
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
the Company's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
industrial and commercial customers and sell energy generation to other
utilities. Also, electricity sales for resale rates are affected by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the 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. 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 the GPSC has held workshops to
discuss retail competition and industry restructuring, there has been no
proposed or enacted legislation to date in Georgia. Enactment would require
numerous issues to be resolved, including significant ones relating to recovery
of any stranded investments, full cost recovery of energy produced, and other
issues related to the energy crisis that occurred in California. As a result of
that crisis, many states have either discontinued or delayed implementation of
initiatives involving retail deregulation. The Company does compete with other
electric suppliers within the state. In Georgia, most new retail customers with
at least 900 kilowatts of connected load may choose their electricity supplier.
In December 1999, the FERC issued its final rule on Regional Transmission
Organizations (RTOs). The order encouraged utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company and its operating companies,
including the Company, have submitted a series of status reports informing the
II-185
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing a for-profit RTO known
as SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to
have a material impact on Southern Company's financial statements. The outcome
of this matter cannot now be determined.
Accounting Policies
Critical Policy
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of Financial
Accounting Standards Board (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 Standards
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change -- effective April
1, 2002 -- in accounting for certain contracts related to fuel supplies that
contain quantity options. These contracts will be accounted for as derivatives
and marked to market. However, due to the existence of the Company's cost-based
fuel recovery clause, this change is not expected to have a material impact on
net income.
On June 1, 2001, the Company implemented a natural gas/oil hedging program
which was ordered by the GPSC as part of the fuel cost recovery increase filing.
The maximum annual dollar amount of the hedges recoverable through the fuel cost
recovery clause is 10 percent of the annual gas/oil budget or $1.5 million for
2001 and $2.4 million for 2002.
In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No. 142 in January 2002 with no material
impact on the financial statements.
Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.
II-186
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
FINANCIAL CONDITION
- -------------------
Overview
The principal change in the Company's financial condition in 2001 was the
addition of $31.3 million to utility plant. The funds needed for gross property
additions are currently provided from operating activities, principally from
earnings, and non-cash charges to income such as depreciation and deferred
income taxes and from financing activities. See Statements of Cash Flows for
additional information.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.
Exposure to Market Risks
Due to cost-based 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. At December 31, 2001,
exposure from these activities was not material to the Company's financial
statements. Also, if the Company sustained a 100 basis point change in interest
rates for all variable rate long-term debt, the change would affect annualized
interest expense by approximately $0.2 million at December 31, 2001. Fair values
of changes in energy trading contracts and year-end valuations are as follows:
Changes
During the Year
-------------------
Fair Value
- --------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 36
Contracts realized or settled (32)
New contracts at inception -
Changes in valuation techniques -
Current period changes (1,057)
- --------------------------------------------------------------
Contracts end of year $(1,053)
==============================================================
Source of Year-End
Valuation Prices
---------------------------------
Maturity
Total --------------------
Fair Value Year 1 1-3 Years
- ---------------------------------------------------------------
(in thousands)
- ---------------------------------------------------------------
Actively quoted $(1,053) $(1,051) $(2)
External sources - - -
Models and other
methods - - -
- ---------------------------------------------------------------
Contracts end of Year $(1,053) $(1,051) $(2)
===============================================================
For additional information, see Note 1 to the financial statements under
"Financial Instruments."
Capital Structure
As of December 31, 2001, the Company's capital structure consisted of 46.8
percent common stockholder's equity, 10.6 percent trust preferred securities,
and 42.6 percent long-term debt, excluding amounts due within one year.
Maturities and retirements of long-term debt were $50.7 million in 2001,
$0.4 million in 2000, and $16.2 million in 1999.
In May 2001, the Company issued $20 million of series B 5.12% senior notes
maturing in 2003 and $45 million of series C 6.55% senior notes maturing in
2008. The Company used these proceeds to redeem its $20 million 6 3/8 Series
First Mortgage Bonds due in 2003, to repay long-term bank loans in the amount of
$30 million, and to repay a portion of its short-term indebtedness.
The composite interest rates and dividend rates for the years 1999 through
2001 as of year-end were as follows:
2001 2000 1999
-------------------------------
Composite interest rates
on long-term debt 5.9% 6.6% 6.4%
Trust preferred securities
dividend rate 6.9% 6.9% 6.9%
- -----------------------------------------------------------------
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$115.7 million ($34.8 million in 2002, $37.6 million in 2003, and $43.3 million
in 2004). Actual construction costs may vary from this estimate because of
II-187
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
factors such as changes in: business conditions; environmental 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. Construction and
upgrading of new and existing transmission and distribution facilities and
upgrading of generating plants will be continuing.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately
$22.5 million will be needed by the end of 2004 for maturities of long-term debt
and present sinking fund requirements.
Capital requirements, lease obligations, and purchase commitments -
discussed in Notes 4 and 6 to the financial statements -- are as follows:
2002 2003 2004
------------------------------------------------------------
(in thousands)
Notes $ - $20,000 $ -
Bonds -
First mortgage 436 - -
Pollution control - - -
Leases -
Capital 742 688 627
Operating 429 429 429
Purchase commitments
Fuel 34,000 300 300
Purchased power 9,944 13,640 13,656
- -------------------------------------------------------------
Credit arrangements at the beginning of 2002, are as follows:
Expires
---------------------------------
Total 2002 2003
---------------------------------------------------------
(in thousands)
$65,500 $45,500 $20,000
- ----------------------------------------------------------
For additional information, see Note 6 to the financial statements under
"Bank Credit Arrangements".
Environmental Matters
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The EPA concurrently issued to Southern Company's operating
companies a notice of violation related to 10 generating facilities, which
includes the five facilities mentioned previously and the Company's Plant Kraft.
In early 2000, the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation, and to add Gulf Power,
Mississippi Power, and the Company as defendants. The complaint and notice of
violation are similar to those brought against and issued to several other
electric utilities. These complaints and notices of violation allege that the
utilities had failed to secure necessary permits or install additional pollution
control equipment when performing maintenance and construction at coal burning
plants constructed or under construction prior to 1978. The U.S. District Court
in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in
Georgia and granted the system service company's motion to dismiss on the
grounds that it neither owned nor operated the generating units involved in the
proceedings. The court granted the EPA's motion to add the Company as a
defendant, but it denied the motion to add Gulf Power and Mississippi Power
based on lack of jurisdiction over those companies. The court directed the EPA
to re-file its amended complaint limiting claims to those brought against
Georgia Power and the Company. The EPA re-filed those claims as directed by the
court. Also, the EPA re-filed its claims against Alabama Power in U.S. District
Court in Alabama. It has not re-filed against Gulf Power, Mississippi Power, or
the system service company. The Alabama Power, Georgia Power, and the Company's
cases have been stayed since the spring of 2001, pending a ruling by the U.S.
Court of Appeals for the Eleventh Circuit in the appeal of a very similar New
Source Review enforcement action against the Tennessee Valley Authority (TVA).
The TVA case involves many of the same legal issues raised by the actions
against Alabama Power, Georgia Power, and the Company. Because the outcome of
II-188
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
the TVA case could have a significant adverse impact on Alabama Power and
Georgia Power, both companies are parties to that case as well. The U.S.
District Court in Alabama has indicated that it will revisit the issue of a
continued stay in April 2002. The U.S. District Court in Georgia is currently
considering a motion by the EPA to reopen the Georgia case. Georgia Power and
the Company have opposed that motion.
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.
In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act--the acid rain compliance
provision of the law--significantly affected the Company and other subsidiaries
of Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants were required in two phases. Phase
I compliance began in 1995. Southern Company's subsidiaries, including the
Company, achieved Phase I compliance at the affected plants by primarily
switching to low-sulfur coal and with some equipment upgrades. The construction
expenditures for Phase I compliance totaled approximately $2 million for the
Company.
Phase II sulfur dioxide compliance was required in 2000. Southern Company
used emission allowances and fuel switching to comply with Phase II
requirements. Phase II compliance had no significant impact on the Company.
A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.
In July 1997, the EPA revised the national ambient air quality standards
for ozone and particulate matter. This revision made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA. In addition, the Federal District of
Columbia Circuit Court of Appeals is considering other legal challenges to these
standards. If the standards are eventually upheld, implementation could be
required by 2007 to 2010.
In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rule affects 21 states, including
Georgia. Compliance is required by May 31, 2004 for most states. For Georgia,
further rulemaking was required, and proposed compliance was delayed until May
1, 2005.
In December 2000, having completed its utility studies for mercury and
other hazardous air pollutants (HAPS), the EPA issued a determination that an
emission control program for mercury and, perhaps, other HAPS is warranted. The
program is being developed under the Maximum Achievable Control Technology
provisions of the Clean Air Act, and the regulations are scheduled to be
finalized by the end of 2004 with implementation to take place around 2007. In
January 2001, the EPA proposed guidance for the determination of Best Available
Retrofit Technology (BART) emission controls under the Regional Haze
Regulations. Installation of BART controls is expected to take place around
2010. Litigation of the Regional Haze Regulations, including the BART
provisions, is ongoing in the Federal District of Columbia Circuit Court of
Appeals. A court decision is expected in mid-2002.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.
II-189
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup and
will recognize in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation--if
any--will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
At December 31, 2001, the Company had $65.5 million of short-term and
revolving credit arrangements with banks to meet its short-term cash needs and
to provide additional interim funding for the Company's construction program.
Revolving credit arrangements total $20 million, of which $10 million expires
April 30, 2003 and $10 million expires December 31, 2003.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $32.2 million of commercial
paper.
The Company's committed credit arrangements provide liquidity support to
the Company's variable rate obligations and to its commercial paper program. The
amount of variable rate obligations outstanding at December 31, 2001 was $22.6
million.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from sources similar to those used in the past. These sources were primarily
from the issuances of first mortgage bonds, other long-term debt, and preferred
stock, in addition to pollution control revenue bonds issued for the Company's
benefit by public authorities, to meet long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company is required to meet certain
earnings coverage requirements specified in its mortgage indenture and corporate
charter to issue new first mortgage bonds and preferred stock. The Company's
coverage ratios are sufficiently high to permit, at present interest rate
levels, any foreseeable security sales. There are no restrictions on the amount
of unsecured indebtedness allowed. The amount of securities which the Company
will be permitted to issue in the future will depend upon market conditions and
other factors prevailing at that time.
II-190
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report
Cautionary Statement Regarding Forward-Looking
Information
This Annual Report includes forward-looking statements in addition to historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
"anticipates," "believes," "estimates," "predicts," "projects," "potential" or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action against the Company; the effects, extent, and timing of the entry of
additional competition in the markets of the Company; the impact of fluctuations
in commodity prices, interest rates, and customer demand; state and federal rate
regulations; political, legal, and economic conditions and developments in the
United States; internal restructuring or other restructuring options that may be
pursued; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or beneficial;
the effects of, and changes in, economic conditions in the United States; the
direct or indirect effects on the Company's business resulting from the
terrorist incidents on September 11, 2001, or any similar such incidents or
responses to such incidents; financial market conditions and the results of
financing efforts; the ability of the Company to obtain additional generating
capacity at competitive prices; weather and other natural phenomena; and other
factors discussed elsewhere herein and in other reports (including the Form
10-K) filed from time to time by the Company with the Securities and Exchange
Commission.
II-191
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Savannah Electric and Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $269,172 $282,622 $242,265
Sales for resale --
Non-affiliates 8,884 4,748 3,395
Affiliates 3,205 4,974 4,151
Other revenues 2,591 3,374 1,783
- ---------------------------------------------------------------------------------------------------------------------
Total operating revenues 283,852 295,718 251,594
- ---------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 50,796 57,177 50,530
Purchased power --
Non-affiliates 23,147 25,229 14,398
Affiliates 49,939 50,111 33,398
Other 50,607 53,086 50,341
Maintenance 19,886 19,334 16,333
Depreciation and amortization (Note 3) 25,951 25,240 23,841
Taxes other than income taxes 13,984 13,116 12,690
- ---------------------------------------------------------------------------------------------------------------------
Total operating expenses 234,310 243,293 201,531
- ---------------------------------------------------------------------------------------------------------------------
Operating Income 49,542 52,425 50,063
Other Income (Expense):
Interest income 173 252 169
Other, net (686) (657) (663)
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 49,029 52,020 49,569
- ---------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 12,517 12,737 11,938
Distributions on preferred securities of subsidiary 2,740 2,740 2,740
- ---------------------------------------------------------------------------------------------------------------------
Total interest and other, net 15,257 15,477 14,678
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 33,772 36,543 34,891
Income taxes (Note 5) 11,731 13,574 11,808
- ---------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 22,041 22,969 23,083
Accounting Change
Cumulative effect of accounting change--
less income taxes of $14 thousand 22 - -
- ---------------------------------------------------------------------------------------------------------------------
Net Income $ 22,063 $ 22,969 $ 23,083
=====================================================================================================================
The accompanying notes are an integral part of these statements.
II-192
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Savannah Electric and Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $22,063 $22,969 $23,083
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 27,895 26,639 25,454
Deferred income taxes and investment tax credits, net (20,528) 728 (3,353)
Other, net 4,084 3,835 (47)
Changes in certain current assets and liabilities --
Receivables, net 24,079 (23,260) (5,999)
Fossil fuel stock (2,711) (31) (2,125)
Materials and supplies (4,025) (542) (1,906)
Accounts payable (8,439) 8,881 1,133
Other 12,631 (4,674) 1,731
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 55,049 34,545 37,971
- ---------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (31,296) (27,290) (29,833)
Other (1,875) (1,835) (1,715)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (33,171) (29,125) (31,548)
- ---------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (13,241) 11,100 34,300
Proceeds --
Other long-term debt 65,000 - -
Capital contributions from parent company 1,561 1,478 1,099
Retirements --
First mortgage bonds (20,642) - (15,800)
Other long-term debt (30,071) (251) (481)
Payment of common stock dividends (21,700) (24,300) (25,200)
Other (394) - 250
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (19,487) (11,973) (5,832)
- ---------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 2,391 (6,553) 591
Cash and Cash Equivalents at Beginning of Period - 6,553 5,962
- ---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 2,391 $ - $ 6,553
===========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $15,340 $13,329 $14,212
Income taxes (net of refunds) $21,034 $19,939 $12,647
- ---------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-193
BALANCE SHEETS
At December 31, 2001 and 2000
Savannah Electric and Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
Assets 2001 2000
- -----------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 2,391 $ -
Receivables --
Customer accounts receivable 29,959 28,189
Under-recovered retail fuel clause revenue 11,974 39,632
Other accounts and notes receivable 2,882 1,412
Affiliated companies 1,170 738
Accumulated provision for uncollectible accounts (500) (407)
Fossil fuel stock, at average cost 9,851 7,140
Materials and supplies, at average cost 12,969 8,944
Prepaid taxes 12,511 8,651
Other 586 377
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 83,793 94,676
- -----------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Note 6) 855,290 829,270
Less accumulated provision for depreciation 402,492 382,030
- -----------------------------------------------------------------------------------------------------------------------
452,798 447,240
Construction work in progress 8,540 6,782
- -----------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 461,338 454,022
- -----------------------------------------------------------------------------------------------------------------------
Other Property and Investments 2,742 2,066
- -----------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 5) 12,283 12,404
Cash surrender value of life insurance for deferred compensation plans 20,002 17,954
Debt expense, being amortized 3,197 3,003
Premium on reacquired debt, being amortized 6,890 7,575
Other 4,498 2,527
- -----------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 46,870 43,463
- -----------------------------------------------------------------------------------------------------------------------
Total Assets $594,743 $594,227
=======================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-194
BALANCE SHEETS
At December 31, 2001 and 2000
Savannah Electric and Power Company 2001 Annual Report
- --------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2001 2000
- --------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 6) $ 1,178 $ 30,698
Notes payable 32,159 45,400
Accounts payable --
Affiliated 5,087 16,153
Other 10,160 7,738
Customer deposits 6,237 5,696
Taxes accrued --
Income taxes 2,587 3,450
Other 1,668 1,435
Interest accrued 4,014 4,541
Vacation pay accrued 2,361 2,276
Other 9,097 7,973
- --------------------------------------------------------------------------------------------------------------------
Total current liabilities 74,548 125,360
- --------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 160,709 116,902
- --------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 5) 77,331 79,756
Deferred credits related to income taxes (Note 5) 13,776 16,038
Accumulated deferred investment tax credits (Note 5) 9,952 10,616
Deferred compensation plans 8,550 7,695
Employee benefits provisions (Note 2) 18,936 13,509
Other 14,023 9,357
- --------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 142,568 136,971
- --------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) (Note 6) 40,000 40,000
- --------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 176,918 174,994
- --------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $594,743 $594,227
====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-195
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Savannah Electric and Power Company 2001 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2001 2000 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt (Note 6):
First mortgage bonds --
Maturity Interest Rates
-------- --------------
July 1, 2003 6.375% $ - $ 20,000
May 1, 2006 6.90% 20,000 20,000
July 1, 2023 7.40% 23,558 24,200
- ---------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 43,558 64,200
- ---------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.88% due June 1, 2001 - 10,000
5.12% due May 15, 2003 20,000 -
6.55% due May 15, 2008 45,000 -
6.625% due March 17, 2015 30,000 30,000
Adjustable rates (6.71% to 6.86% at 1/1/01)
due 2001 - 20,000
- ---------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 95,000 60,000
- ---------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Non-collateralized:
Variable rates (1.90% at 1/1/02)
due 2016-2037 17,955 17,955
- ---------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 17,955 17,955
- ---------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 5,374 5,445
- ---------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $9.6 million) 161,887 147,600
Less amount due within one year (Note 6) 1,178 30,698
- ---------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 160,709 116,902 42.6% 35.2%
- ---------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 6):
$25 liquidation value --
6.85% 40,000 40,000
- ---------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million) 40,000 40,000 10.6 12.1
- ---------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (Note 6):
Common stock, par value $5 per share --
Authorized - 16,000,000 shares
Outstanding - 10,844,635 shares in 2001 and 2000
Par value 54,223 54,223
Paid-in capital 12,826 11,265
Retained earnings 109,869 109,506
- ---------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 176,918 174,994 46.8 52.7
- ---------------------------------------------------------------------------------------------------------------------------
Total Capitalization $377,627 $331,896 100.0% 100.0%
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-196
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Savannah Electric and Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------
Common Paid-In Retained
Stock Capital Earnings Total
- ----------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1999 $54,223 $ 8,688 $112,954 $175,865
Net income - - 23,083 23,083
Capital contributions from parent company - 1,099 - 1,099
Cash dividends on common stock - - (25,200) (25,200)
- ----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 54,223 9,787 110,837 174,847
Net income - - 22,969 22,969
Capital contributions from parent company - 1,478 - 1,478
Cash dividends on common stock - - (24,300) (24,300)
- ----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 54,223 11,265 109,506 174,994
Net income - - 22,063 22,063
Capital contributions from parent company - 1,561 - 1,561
Cash dividends on common stock - - (21,700) (21,700)
- ----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 (Note 6) $54,223 $12,826 $109,869 $176,918
======================================================================================================================
The accompanying notes are an integral part of these statements.
II-197
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2001 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Savannah Electric and Power Company (the Company) is a wholly owned subsidiary
of Southern Company, which is the parent company of five operating companies, a
system service company, Southern Communications Services (Southern LINC),
Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company
(Southern Power), and other direct and indirect subsidiaries. The operating
companies provide electric service in four states. Contracts among the operating
companies--related to jointly owned generating facilities, interconnecting
transmission lines, and the exchange of electric power--are regulated by the
Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange
Commission. The system service company provides, at cost, specialized services
to Southern Company and subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Power was
established in 2001 to construct, own, and manage Southern Company's competitive
generation assets and sell electricity at market-based rates in the wholesale
market.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
also is subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows accounting principles generally accepted
in the United States and complies with the accounting policies and practices
prescribed by the GPSC. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the
use of estimates, and the actual results may differ from those estimates.
Certain prior years' data presented in the financial statements has been
reclassified to conform with the current year presentation.
Affiliate Transactions
The Company has an agreement with the system service company under which the
following services are rendered to the Company at cost: general and design
engineering, purchasing, accounting and statistical, finance and treasury, tax,
information resources, marketing, auditing, insurance and employee benefits,
human resources, systems and procedures, and other administrative services with
respect to business and operations and power pool operations. Costs for these
services amounted to $15.0 million, $15.1 million, and $16.0 million during
2001, 2000, and 1999, 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. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:
2001 2000
--------------------------
(in thousands)
Deferred income tax charges $ 12,283 $ 12,404
Premium on reacquired debt 6,890 7,575
Gas by-pass facility 209 299
Deferred income tax credits (13,776) (16,038)
Storm damage reserves (4,228) (2,733)
Accelerated depreciation (8,000) (5,500)
- ---------------------------------------------------------------
Total $ (6,622) $ (3,993)
===============================================================
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 value.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area of
southeastern Georgia and to wholesale customers in the Southeast.
II-198
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is
used. Electric rates for the Company include provisions to adjust billings for
fluctuations in fuel costs, the energy component of purchased power costs, and
certain other 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 averaged less than 1 percent of revenues.
In 2001, the GPSC approved an increase in the Company's fuel cost recovery
rate amounting to a total average annual rate increase of 18 percent for all
customer classes. An increase of slightly over one-third of a cent per
kilowatt-hour was approved in 2000.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.0 percent in 2001,
2000, and 1999. When property subject to depreciation is retired or otherwise
disposed of in the normal course of business, its cost--together with the cost
of removal, less salvage--is charged to 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 removal of certain facilities. In
2001, 2000, and 1999, the Company recorded accelerated depreciation of $2.5
million, $2.5 million, and $2.0 million, respectively, in accordance with the
GPSC's 1998 rate order. See Note 3 to the financial statements for more
information.
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 rates used by the Company to calculate AFUDC
were 5.13 percent in 2001, 6.87 percent in 2000, and 6.26 percent in 1999.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory
disallowances and impairments. Original cost includes: materials; labor; minor
items of property; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits, and AFUDC. 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.
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 costs 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.
Financial Instruments
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on net
income was immaterial. The Company uses derivative financial instruments to
hedge exposure to fluctuations in certain commodity prices. Gains and losses on
qualifying hedges are deferred and recognized either as income or as an
adjustment to the carrying amount of the hedged item when the transaction
occurs.
II-199
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.
The five operating companies and Southern Power enter into commodity related
forward and option contracts to limit exposure to changing prices on certain
fuel purchases and electricity purchases and sales. Substantially all of
Southern Company's bulk energy purchases and sales contracts meet the definition
of a derivative under FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities. In many cases, these fuel and electricity
contracts qualify for normal purchase and sale exceptions under Statement No.
133 and are accounted for under the accrual method. Other contracts qualify as
cash flow hedges of anticipated transactions, resulting in the deferral of
related gains and losses, and are recorded in other comprehensive income until
the hedged transactions occur. Any ineffectiveness is recognized currently in
net income. Contracts that do not qualify for the normal purchase and sale
exception and that do not meet the hedge requirements are marked to market
through current period income.
On June 1, 2001, the Company implemented a natural gas/oil hedging program
which was ordered by the GPSC as part of the fuel cost recovery increase filing.
The maximum annual dollar amount of the hedges recoverable through the fuel cost
recovery clause is 10 percent of the annual gas/oil budget or $1.5 million for
2001 and $2.4 million for 2002.
The Company's other financial instruments for which the carrying amounts
did not equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
(in millions)
Long-term debt:
At December 31, 2001 $157 $157
At December 31, 2000 $142 $140
Trust preferred securities:
At December 31, 2001 $40 $38
At December 31, 2000 $40 $36
The fair values for long-term debt and trust preferred securities were
based on either closing market prices or closing prices of comparable
instruments.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, non-contributory pension plans that
cover substantially all employees. The Company provides certain medical care and
life insurance benefits for retired employees. The Company funds trusts to the
extent required by the GPSC and the FERC. The measurement date for plan assets
and obligations is September 30 of each year. In late 2000, the Company adopted
several pension and postretirement benefit plan changes that had the effect of
increasing benefits to both current and future retirees.
Pension Plans
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
2001 2000
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $71,521 $66,509
Service cost 2,074 1,844
Interest cost 5,426 4,854
Benefits paid (3,986) (3,469)
Actuarial loss and
employee transfers 894 1,564
Amendments 3,621 219
- ---------------------------------------------------------------
Balance at end of year $79,550 $71,521
===============================================================
Plan Assets
---------------------------
2001 2000
- --------------------------------========================-------
(in thousands)
Balance at beginning of year $61,880 $54,480
Actual return on plan assets (8,911) 10,493
Benefits paid (3,570) (3,210)
Employee transfers 1,459 117
- ---------------------------------====================----------
Balance at end of year $50,858 $61,880
===============================================================
II-200
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
The accrued pension costs recognized in the Balance Sheets
were as follows:
2001 2000
- ---------------------------------------------------------------
(in thousands)
Funded status $(28,692) $(9,641)
Unrecognized transition
obligation - 89
Unrecognized prior service
cost 7,401 4,391
Unrecognized net loss (gain) 12,336 (235)
- ---------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $ (8,955) $(5,396)
===============================================================
Components of the pension plan's net periodic cost were as follows:
2001 2000 1999
- -----------------------------------------------------------------
(in thousands)
Service cost $ 2,074 $ 1,844 $ 1,838
Interest cost 5,426 4,854 4,327
Expected return on plan
assets (4,215) (4,174) (4,063)
Recognized net loss 16 - 171
Net amortization 700 503 478
- -----------------------------------------------------------------
Net pension cost $ 4,001 $ 3,027 $ 2,751
=================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
---------------------------
2001 2000
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $26,124 $22,904
Service cost 433 376
Interest cost 2,022 1,865
Benefits paid (987) (963)
Actuarial gain and
employee transfers (1,214) (1,367)
Amendments 1,743 3,309
- ---------------------------------------------------------------
Balance at end of year $28,121 $26,124
===============================================================
Plan Assets
---------------------------
2001 2000
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $6,910 $5,254
Actual return on plan assets (789) 606
Employer contributions 2,267 2,013
Benefits paid (987) (963)
- ---------------------------------------------------------------
Balance at end of year $7,401 $6,910
===============================================================
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
2001 2000
- ---------------------------------------------------------------
(in thousands)
Funded status $(20,720) $(19,214)
Unrecognized transition
obligation 5,431 5,925
Unamortized prior service cost 4,691 3,185
Unrecognized net loss 1,831 1,701
Fourth quarter contributions 1,577 1,493
- ---------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $ (7,190) $ (6,910)
===============================================================
Components of the postretirement plan's net periodic cost were as follows:
2001 2000 1999
- ----------------------------------------------------------------
(in thousands)
Service cost $ 433 $ 376 $ 404
Interest cost 2,022 1,865 1,549
Expected return on plan assets (555) (429) (345)
Recognized net loss - 66 152
Net amortization 731 618 494
- ----------------------------------------------------------------
Net postretirement cost $2,631 $2,496 $2,254
================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plan and postretirement benefits plan were:
2001 2000
- -------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Long-term return on plan assets 8.50 8.50
- -------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
II-201
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in thousands)
Benefit obligation $2,070 $2,051
Service and interest costs 181 179
===============================================================
The Company has a supplemental retirement plan for certain executive
employees. The plan is unfunded and payable from the general funds of the
Company. The Company has purchased life insurance on participating executives
and plans to use these policies to satisfy this obligation.
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $1.0
million, $0.9 million, and $0.9 million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The Clean Air Act authorizes civil penalties of up to $27,500
per day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.
The EPA concurrently issued to the operating companies a notice of violation
related to 10 generating facilities, which includes the five facilities
mentioned previously and the Company's Plant Kraft. In early 2000, the EPA filed
a motion to amend its complaint to add the violations alleged in its notice of
violation, and to add Gulf Power, Mississippi Power, and the Company as
defendants. The complaint and notice of violation are similar to those brought
against and issued to several other electric utilities. These complaints and
notices of violation allege that the utilities had failed to secure necessary
permits or install additional pollution control equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. The U.S. District Court in Georgia granted Alabama
Power's motion to dismiss for lack of jurisdiction in Georgia and granted the
system service company's motion to dismiss on the grounds that it neither owned
nor operated the generating units involved in the proceedings. The court granted
the EPA's motion to add the Company as a defendant, but it denied the motion to
add Gulf Power and Mississippi Power based on lack of jurisdiction over those
companies. The court directed the EPA to re-file its amended complaint limiting
claims to those brought against Georgia Power and the Company. The EPA re-filed
those claims as directed by the court. Also, the EPA re-filed its claims against
Alabama Power in U.S. District Court in Alabama. It has not re-filed against
Gulf Power, Mississippi Power, or the system service company.
The Alabama Power, Georgia Power, and the Company's cases have been stayed
since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the
Eleventh Circuit in the appeal of a very similar New Source Review enforcement
action against the Tennessee Valley Authority (TVA). The TVA case involves many
of the same legal issues raised by the actions against Alabama Power, Georgia
Power, and the Company. Because the outcome of the TVA case could have a
II-202
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
significant adverse impact on Alabama Power and Georgia Power, both companies
are parties to that case as well. The U.S. District Court in Alabama has
indicated that it will revisit the issue of a continued stay in April 2002. The
U.S. District Court in Georgia is currently considering a motion by the EPA to
reopen the Georgia case. Georgia Power and the Company have opposed that motion.
The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
Retail Regulatory Matters
Rates to retail customers served by the Company are regulated by the GPSC. As
part of the Company's rate settlement in 1992, it was informally agreed that the
Company's earned rate of return on common equity should be 12.95 percent.
In 1998, the GPSC approved a four-year accounting order for the Company.
Under this order, the Company will reduce the electric rates of its small
business customers by approximately $11 million over four years. The Company
will also expense an additional $1.95 million in storm damage accruals and
accrue an additional $8 million in depreciation on generating assets over the
term of the order. The additional depreciation will be accumulated in a
regulatory liability account to be available to mitigate any potential stranded
costs. In addition, the Company has discretionary authority to provide up to an
additional $0.3 million per year in storm damage accruals and up to an
additional $4.0 million in depreciation expense over the four years. Total storm
damages accrued under the order were $1.5 million per year in 2001, 2000, and
1999 which included discretionary expense of $0.3 million in each year. No
discretionary depreciation was recorded in the last three years. Over the term
of the order, the Company is precluded from asking for a rate increase except
upon significant changes in economic conditions, new laws, or regulations. There
is a quarterly monitoring of the Company's earnings performance.
The Company filed a base rate case November 30, 2001 for the first time
since 1985. The primary reason for this base rate case is to recover significant
new costs related to the 200 megawatt Plant Wansley power purchase agreement
beginning June 2002, as well as other operation and maintenance expense changes.
The requested increase is 7.6 percent of total rates (base plus fuel). In the
filing, the Company announced it would file in early 2002 for a fuel decrease
which would offset most, if not all, of the base rate increase.
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated
to total $34.8 million in 2002, $37.6 million in 2003, and $43.3 million in
2004. The construction program is subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include: changes in business conditions; revised load
growth estimates; changes in environmental regulations; increasing costs of
labor, equipment, and materials; and changes in cost of capital. The Company
does not have any traditional baseload generating plants under construction.
However, construction related to new and upgrading of existing transmission and
distribution facilities and the upgrading of generating plants will continue.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. The Company has fuel
commitments of $34 million for 2002, $0.3 million for each of the four years
2003 through 2006, and $6 million for 2007 and beyond.
In addition, the system service company acts as agent for the Company and
the other operating companies and Southern Power with regard to natural gas
purchases. Natural gas purchases (in dollars) are based on various indices at
the actual time of delivery; therefore, only the volume commitments are firm.
The Company's committed volumes allocated based on usage projections as of
II-203
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
December 31, 2001 are as follows:
Year Natural Gas
- ---- -------------
(MMBtu)
2002 4,765,152
2003 4,356,394
2004 3,049,457
2005 2,115,548
2006 1,804,674
2007 and beyond 612,901
- ---------------------------------------------------------------
Total commitments 16,704,126
===============================================================
The Company has entered into various long-term commitments for the purchase
of electricity, substantially all from affiliated companies, including the Plant
Wansley purchased power agreement. Estimated total long-term obligations at
December 31, 2001 were as follows:
Year Commitments
- ---- --------------
(in thousands)
2002 $ 9,944
2003 13,640
2004 13,656
2005 13,670
2006 13,686
2007 and beyond 41,152
- ---------------------------------------------------------------
Total commitments $105,748
===============================================================
Operating Leases
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $0.4 million for 2001, $0.4 million for 2000, and $0.5
million for 1999.
At December 31, 2001, estimated future minimum lease payments for
noncancelable operating leases were as follows:
Rental
Commitments
---------------
(in thousands)
2002 $429
2003 429
2004 429
2005 429
2006 429
2007 and thereafter 4,894
- --------------------------------------------------------------
Total commitments $7,039
==============================================================
5. INCOME TAXES
At December 31, 2001, tax-related regulatory assets and liabilities were $12.3
million and $13.8 million, respectively. The assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized interest. The liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of income tax provisions are as follows:
2001 2000 1999
---------------------------
(in thousands)
Total provision for income taxes
Federal --
Currently payable $ 27,991 $11,102 $12,968
Deferred (17,951) 75 (3,329)
- ------------------------------------------------------------------
10,040 11,177 9,639
- ------------------------------------------------------------------
State --
Currently payable 4,282 1,744 2,193
Deferred (2,577) 653 (24)
- ------------------------------------------------------------------
1,705 2,397 2,169
- ------------------------------------------------------------------
Total $ 11,745 $13,574 $11,808
==================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
2001 2000
---------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $81,654 $76,901
Property basis differences (1,437) 5,904
Other 6,566 17,807
- ------------------------------------------------------------------
Total 86,783 100,612
- ------------------------------------------------------------------
Deferred tax assets:
Pension and other benefits 11,403 9,744
Other 10,560 7,662
- ------------------------------------------------------------------
Total 21,963 17,406
- ------------------------------------------------------------------
Total deferred tax liabilities, net 64,820 83,206
Portion included in current assets
(liabilities), net 12,511 (3,450)
- ------------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $77,331 $79,756
==================================================================
In accordance with regulatory requirements, deferred investment tax credits
are amortized over the lives of the related property with such amortization
normally applied as a credit to reduce depreciation in the Statements of Income.
II-204
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
Credits amortized in this manner amounted to $0.7 million per year in 2001,
2000, and 1999. At December 31, 2001, all investment tax credits available to
reduce federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
2001 2000 1999
-----------------------------
Federal statutory tax rate 35% 35% 35%
State income tax, net of
Federal income tax benefit 3 4 4
Other (3) (2) (5)
----------------------------------------------------------------
Effective income tax rate 35% 37% 34%
================================================================
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. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.
6. CAPITALIZATION
Trust Preferred Securities
In December 1998, Savannah Electric Capital Trust I, of which the Company owns
all of the common securities, issued $40 million of 6.85% mandatorily redeemable
preferred securities. Substantially all of the assets of the Trust are $40
million aggregate principal amount of the Company's 6.85% junior subordinated
notes due December 31, 2028.
The Company considers that the mechanisms and obligations relating to the
trust preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of payment obligations with respect to the preferred
securities of Savannah Electric Capital Trust I.
Savannah Electric Capital Trust I is a subsidiary of the Company, and
accordingly is consolidated in the Company's financial statements.
Long-Term Debt and Capital Leases
The Company's Indenture related to its First Mortgage Bonds is unlimited as to
the authorized amount of bonds which may be issued, provided that required
property additions, earnings, and other provisions of such Indenture are met.
Maturities and retirements of long-term debt were $50.7 million in 2001,
$0.4 million in 2000, and $16.2 million in 1999.
In May 2001, the Company issued $20 million of series B 5.12% senior notes
maturing May 15, 2003 and $45 million of series C 6.55% senior notes maturing
May 15, 2008. The Company used these proceeds to redeem its $20 million 6 3/8
Series First Mortgage Bonds due July 1, 2003, to repay long-term bank loans in
the amount of $30 million, and to repay a portion of its short-term
indebtedness.
Assets acquired under capital leases are recorded as utility plant in
service, and the related obligation is classified as other long-term debt.
Leases are capitalized at the net present value of the future lease payments.
However, for ratemaking purposes, these obligations are treated as operating
leases, and as such, lease payments are charged to expense as incurred.
Securities Due Within One Year
A summary of the sinking fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
2001 2000
---------------------
(in thousands)
Bond sinking fund requirement $436 $ 642
Less:
Portion to be satisfied by
certifying property additions - 642
- -------------------------------------------------------- ----------
Cash sinking fund requirement 436 -
Other long-term debt maturities 742 30,698
- -------------------------------------------------------------------
Total $1,178 $30,698
===================================================================
The first mortgage bond improvement (sinking) fund requirements amount to 1
percent of each outstanding series of bonds authenticated under the Indenture
prior to January 1 of each year, other than those issued to collateralize
pollution control and other obligations. The requirements may be satisfied by
depositing cash or reacquiring bonds, or by pledging additional property equal
to 1 2/3 times the requirements.
The sinking fund requirements of first mortgage bonds were satisfied by
cash redemption in 2001 and by certifying property additions in 2000. It is
anticipated that the 2002 requirement will be satisfied by cash redemption.
II-205
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report
Sinking fund requirements and/or maturities through 2006 applicable to long-term
debt are as follows: $1.2 million in 2002; $20.7 million in 2003; $0.6 million
in 2004; $0.6 million in 2005; and $20.6 million in 2006.
Bank Credit Arrangements
At the end of 2001, unused credit arrangements with five banks totaled $65.5
million and expire at various times during 2002 and 2003.
The Company has revolving credit arrangements of $20 million, of which $10
million expires April 30, 2003 and $10 million expires December 31, 2003. One of
these agreements allows short-term borrowings to be converted into term loans,
payable in 12 equal quarterly installments, with the first installment due at
the end of the first calendar quarter after the applicable termination date or
at an earlier date at the Company's option.
In connection with these credit arrangements, the Company agrees to pay
commitment fees based on the unused portions of the commitments.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $32.2 million of commercial
paper.
The Company's committed credit arrangements provide liquidity support to
the Company's variable rate obligations and to its commercial paper program. The
amount of variable rate obligations outstanding at December 31, 2001 was $22.6
million.
Assets Subject to Lien
As amended and supplemented, the Company's Indenture of Mortgage, which secures
the first mortgage bonds issued by the Company, constitutes a direct first lien
on substantially all of the Company's fixed property and franchises. A second
lien for $14 million in pollution control obligations is secured by a portion of
the Plant McIntosh property.
Common Stock Dividend Restrictions
The Company's Indenture contains certain limitations on the payment of cash
dividends on common stock. At December 31, 2001, approximately $68 million of
retained earnings was restricted against the payment of cash dividends on common
stock under the terms of the Indenture.
7. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 2001 and 2000 are as follows (in
thousands):
Net Income After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ------------------------------------------------------------------
March 2001 $61,691 $ 6,799 $ 1,476
June 2001 73,970 14,620 6,246
September 2001 93,583 22,332 11,309
December 2001 54,608 5,791 3,032
March 2000 $52,390 $ 6,583 $ 1,643
June 2000 72,780 14,904 6,287
September 2000 98,849 24,461 12,351
December 2000 71,699 6,477 2,688
- ---------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.
II-206
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Savannah Electric and Power Company 2001 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $283,852 $295,718 $251,594 $254,455 $226,277
Net Income after Dividends
on Preferred Stock (in thousands) $22,063 $22,969 $23,083 $23,644 $23,847
Cash Dividends
on Common Stock (in thousands) $21,700 $24,300 $25,200 $23,500 $20,500
Return on Average Common Equity (percent) 12.54 13.13 13.16 13.44 13.71
Total Assets (in thousands) $594,743 $594,227 $570,218 $555,799 $547,352
Gross Property Additions (in thousands) $31,296 $27,290 $29,833 $18,071 $18,846
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $176,918 $174,994 $174,847 $175,865 $175,631
Preferred stock - - - - 35,000
Company obligated mandatorily
redeemable preferred securities 40,000 40,000 40,000 40,000 -
Long-term debt 160,709 116,902 147,147 163,443 142,846
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $377,627 $331,896 $361,994 $379,308 $353,477
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.8 52.7 48.3 46.4 49.7
Preferred stock - - - - 9.9
Company obligated mandatorily
redeemable preferred securities 10.6 12.1 11.0 10.5 -
Long-term debt 42.6 35.2 40.7 43.1 40.4
- ----------------------------------------------------------------------------------------------------------------------------------
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+ AA- AA- AA-
Preferred Stock -
Moody's Baa1 a2 a2 a2 a2
Standard and Poor's BBB+ BBB+ A- A A
Unsecured Long-Term Debt -
Moody's A2 - - - -
Standard and Poor's A - - - -
==================================================================================================================================
Customers (year-end):
Residential 117,199 115,646 112,891 110,437 109,092
Commercial 16,121 15,727 15,433 15,328 14,233
Industrial 76 75 67 63 64
Other 474 444 417 377 1,129
- ----------------------------------------------------------------------------------------------------------------------------------
Total 133,870 131,892 128,808 126,205 124,518
==================================================================================================================================
Employees (year-end): 550 554 533 542 535
- ----------------------------------------------------------------------------------------------------------------------------------
II-207
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Savannah Electric and Power Company 2001 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $123,819 $129,520 $112,371 $109,393 $96,587
Commercial 100,835 102,116 88,449 86,231 78,949
Industrial 34,971 40,839 32,233 37,865 35,301
Other 9,547 10,147 9,212 8,838 8,621
- -----------------------------------------------------------------------------------------------------------------------------
Total retail 269,172 282,622 242,265 242,327 219,458
Sales for resale - non-affiliates 8,884 4,748 3,395 4,548 3,467
Sales for resale - affiliates 3,205 4,974 4,151 3,016 2,052
- -----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 281,261 292,344 249,811 249,891 224,977
Other revenues 2,591 3,374 1,783 4,564 1,300
- -----------------------------------------------------------------------------------------------------------------------------
Total $283,852 $295,718 $251,594 $254,455 $226,277
=============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,658,735 1,671,089 1,579,068 1,539,792 1,428,337
Commercial 1,388,357 1,369,448 1,287,832 1,236,337 1,156,078
Industrial 787,674 800,150 713,448 900,012 881,261
Other 133,967 135,824 132,555 131,142 124,490
- -----------------------------------------------------------------------------------------------------------------------------
Total retail 3,968,733 3,976,511 3,712,903 3,807,283 3,590,166
Sales for resale - non-affiliates 111,145 77,481 51,548 53,294 94,280
Sales for resale - affiliates 87,799 88,646 76,988 58,415 54,509
- -----------------------------------------------------------------------------------------------------------------------------
Total 4,167,677 4,142,638 3,841,439 3,918,992 3,738,955
=============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.46 7.75 7.12 7.10 6.76
Commercial 7.26 7.46 6.87 6.97 6.83
Industrial 4.44 5.10 4.52 4.21 4.01
Total retail 6.78 7.11 6.52 6.36 6.11
Sales for resale 6.08 5.85 5.87 6.77 3.71
Total sales 6.75 7.06 6.50 6.38 6.02
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,241 14,593 14,100 14,061 13,231
Residential Average Annual
Revenue Per Customer $1,063.07 $1,131.08 $1,003.39 $998.94 $894.73
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 788 788 788 788 788
Maximum Peak-Hour Demand (megawatts):
Winter 758 724 719 582 625
Summer 846 878 875 846 802
Annual Load Factor (percent) 55.9 53.4 51.2 54.9 54.3
Plant Availability Fossil-Steam (percent): 81.2 78.5 72.8 72.9 93.7
- -----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 50.5 51.6 44.6 41.6 34.4
Oil and gas 4.0 6.9 12.3 12.9 5.2
Purchased power -
From non-affiliates 5.3 7.7 5.3 3.4 1.4
From affiliates 40.2 33.8 37.8 42.1 59.0
- -----------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
=============================================================================================================================
II-208
PART III
Items 10, 11, 12 and 13 for SOUTHERN are incorporated by reference to ELECTION
OF DIRECTORS in SOUTHERN's definitive Proxy Statement relating to the 2002
Annual Meeting of Stockholders.
Additionally, Items 10, 11, 12 and 13 for ALABAMA, GEORGIA, GULF and
MISSISSIPPI are incorporated by reference to the Information Statements of
ALABAMA, GEORGIA, GULF and MISSISSIPPI relating to each of their respective 2002
Annual Meetings of Shareholders.
The ages of directors and executive officers in Item 10 set forth below are
as of December 31, 2001.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Identification of directors of SAVANNAH.
Anthony R. James
President and Chief Executive Officer
Age 51
Served as Director since 5-3-01
Gus H. Bell (1)
Age 64
Served as Director since 7-20-99
Archie H. Davis (1)
Age 60
Served as Director since 2-18-97
Walter D. Gnann (1)
Age 66
Served as Director since 5-17-83
Robert B. Miller, III (1)
Age 56
Served as Director since 5-17-83
Arnold M. Tenenbaum (1)
Age 65
Served as Director since 5-17-77
(1) No position other than Director.
Each of the above is currently a director of SAVANNAH, serving a term
running from the last annual meeting of SAVANNAH's stockholder (May 3, 2001) for
one year until the next annual meeting or until a successor is elected and
qualified, except for Mr. James, whose election was effective on the date
indicated.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of SAVANNAH acting solely in their capacities as such.
Identification of executive officers of SAVANNAH.
Anthony R. James
President, Chief Executive Officer and Director
Age 51
Served as Executive Officer since 7-27-00
W. Miles Greer
Vice President - Customer Operations and
External Affairs
Age 58
Served as Executive Officer since 11-20-85
Sandra R. Miller
Vice President - Power Generation
Age 49
Served as Executive Officer since 7-26-01
Kirby R. Willis
Vice President, Treasurer and Chief Financial Officer
Age 50
Served as Executive Officer since 1-1-94
Each of the above is currently an executive officer of SAVANNAH, serving a
term running from the meeting of the directors held on July 26, 2001 for the
ensuing year.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as an officer, other than any arrangements or understandings with
officers of SAVANNAH acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships.
None.
III-1
Business experience.
Anthony R. James - President and Chief Executive Officer since 2001. He
previously served as Vice President of Power Generation and Senior Production
Officer from 2000 to 2001 and also as Central Cluster Manager at GEORGIA's Plant
Scherer from 2000 to 2001. He served as Plant Manager at GEORGIA's Plant Scherer
from 1996 to 2000. Director of SunTrust Bank of Savannah.
Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell
and DeYoung, Inc., (specializing in environmental, industrial, structural,
architectural and civil engineering), Savannah, Georgia. Director of SunTrust
Bank of Savannah.
Archie H. Davis - President and Chief Executive Officer of The Savannah Bancorp
and Chief Executive Officer of The Savannah Bank, N.A., Savannah, Georgia.
Member of the Board of Directors of Thomaston Mills, Thomaston, Georgia.
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc.,
Springfield, Georgia.
Robert B. Miller, III - President of American Building Systems, Inc., Savannah,
Georgia.
Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation.
Director of First Union Bank of Georgia, First Union
Bank of Savannah and Cerulean Corporation.
W. Miles Greer - Vice President of Customer Operations and External Affairs
since 1998. He previously served as Vice President of Marketing and Customer
Service from 1994 to 1998. Responsible for customer services, transmission and
distribution, engineering, system operation and external affairs.
Sandra R. Miller - Vice President of Power Generation since 2001. She previously
served as Manager of Technical Training at SCS from 1998 to 2001 and Team Leader
at GEORGIA's Plant Bowen from June 1996 to June 1998. Responsible for operations
and maintenance of Plants Kraft, Riverside and McIntosh.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since
1994 and Assistant Corporate Secretary since 1998. Responsible primarily for
accounting, financial, labor relations, corporate services, corporate
compliance, environmental and safety activities.
Involvement in certain legal proceedings.
None
Section 16(a) Beneficial Ownership Reporting
Compliance.
No late filers.
III-2
Item 11. EXECUTIVE COMPENSATION
Summary Compensation Table. The following table sets forth information
concerning any Chief Executive Officer and the three most highly compensated
executive officers of SAVANNAH serving during 2001.
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- ------------------------------------------------------------------------------------------------------------------------
G. Edison
Holland, Jr.4
President, 2001 333,539 324,022 3,692 68,071 - 49,827
Chief Executive 2000 295,812 243,263 24,438 25,667 - 15,453
Officer, Director 1999 254,914 42,626 21,588 8,375 166,052 13,392
Anthony R. James5
President, Chief 2001 210,856 177,858 1,328 31,363 - 30,195
Executive Officer, 2000 175,048 161,442 - 12,752 - 7,582
Director 1999 - - - - - -
W. Miles Greer 2001 184,066 104,286 666 32,505 - 8,567
Vice President 2000 177,013 100,923 601 13,416 - 16,982
1999 168,713 21,322 1,874 6,130 79,476 15,150
Kirby R. Willis
Vice President, 2001 168,747 100,480 490 29,993 - 8,495
Chief Financial 2000 162,279 97,394 4,908 8,785 - 12,159
Officer, Treasurer 1999 156,068 19,546 259 5,028 79,476 11,767
Sandra R. Miller6 2001 112,802 83,015 8,123 1,896 - 20,749
Vice President 2000 - - - - - -
1999 - - - - - -
- -----------------------------------
1 Tax reimbursement by SAVANNAH on certain personal benefits.
2 Payouts made in 2000 for the four-year performance period ending December 31, 1999.
3 SAVANNAH contributions in 2001 to the Employee Savings Plan (ESP), Employee
Stock Ownership Plan (ESOP), Supplemental Benefit Plan (SBP) or Above-Market
Earnings on deferred compensation (AME) and tax sharing benefits paid to
participants who elected receipt of dividends on SOUTHERN's common stock held in
the ESP are as follows:
Name ESP ESOP SBP or AME ESP Tax Sharing Benefits
- ---- --- ---- ---------- ------------------------
G. Edison Holland, Jr. $6,853 $764 $9,861 $721
Anthony R. James 6,853 764 3,181 -
W. Miles Greer 7,650 764 153 -
Kirby R. Willis 5,923 764 1,808 -
Sandra R. Miller 5,051 698 - -
In 2001, this amount for Mr. Holland, Mr. James and Ms. Miller includes
$31,628, $19,397 and $15,000, respectively, of additional incentive
compensation.
4 Mr. Holland transferred to SOUTHERN on May 1, 2001.
5 Mr. James became President and Chief Executive Officer effective May 1, 2001.
6 Ms. Miller became an executive officer of SAVANNAH on July 26, 2001.
III-3
STOCK OPTION GRANTS IN 2001
Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of SAVANNAH during the year ending December 31,
2001.
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted7 Fiscal Year8 ($/Sh)7 Date7 Present Value($)9
-----------------------------------------------------------------------------------------------------------------
SAVANNAH
G. Edison Holland, Jr. 33,159 17 19.0762 2/16/2011 146,894
34,912 17 22.4250 4/16/2011 166,530
Anthony R. James 17,794 9 19.0762 2/16/2011 78,827
13,569 7 22.4250 4/16/2011 64,724
W. Miles Greer 17,007 8 19.0762 2/16/2011 75,341
15,498 8 22.4250 4/16/2011 73,925
Kirby R. Willis 15,591 8 19.0762 2/16/2011 69,068
14,402 7 22.4250 4/16/2001 68,698
Sandra R. Miller 1,337 1 19.0762 2/16/2011 5,923
559 0 22.4250 4/16/2011 2,666
- -------------------------------
7 Under the terms of the Omnibus Incentive Compensation Plan, stock option
grants were made on February 16, 2001 and April 16, 2001, and vest annually at a
rate of one-third on the anniversary date of the grant. Grants fully vest upon
termination as a result of death, total disability or retirement and expire five
years after retirement, three years after death or total disability or their
normal expiration date if earlier. The exercise price is the average of the high
and low price of SOUTHERN's common stock on the date granted. Options may be
transferred to certain family members, family trusts and family limited
partnerships. The number of options granted on February 16, 2001 and the
exercise price thereof were adjusted after the spin-off of Mirant under the
antidilution provisions of the plan such that the options had the same aggregate
intrinsic value on the day of the spin-off as the day before.
8 A total of 200,946 stock options were granted in 2001.
9 Value was calculated using the Black-Scholes option valuation model. The
actual value, if any, ultimately realized depends on the market value of
SOUTHERN's common stock at a future date. Significant assumptions are shown
below:
Risk-free Dividend Discount for forfeiture risk:
Grant Volatility rate of return opportunity Term before after
Date vesting vesting
- -------------------------------------------------------------------------------------------------------------------
2/16/01 25.63% 4.83% 50% 10 7.79% 12.45%
4/16/01 26.50% 4.65% 50% 10 7.79% 11.77%
- -------------------------------------------------------------------------------------------------------------------
These assumptions reflect the effects of cash dividend equivalents paid to
participants under SOUTHERN's Performance Dividend Plan assuming targets are met.
III-4
AGGREGATED STOCK OPTION EXERCISES IN 2001 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 2001 by the
named executive officers and the value of unexercised options held by them as of
December 31, 2001.
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options at Options at
Fiscal Fiscal
Year-End (#) Year-End($)10
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)11 Unexercisable Unexercisable
- --------------------------------------------------------------------------------------------------------------
SAVANNAH
G. Edison Holland, Jr. 38,297 419,217 35,004/99,611 325,235/637,703
Anthony R. James 6,757 67,947 17,972/47,384 166,611/317,077
W. Miles Greer - - 29,132/49,916 288,866/331,185
Kirby R. Willis 6,218 55,902 25,096/41,929 248,549/261,847
Sandra R. Miller - - 560/3,015 5,980/21,972
- ----------------------------
10 This column represents the excess of the fair market value of SOUTHERN's
common stock of $25.35 per share, as of December 31, 2001, above the exercise
price of the options. The Exercisable column reports the "value" of options that
are vested and therefore could be exercised. The Unexercisable column reports
the "value" of options that are not vested and therefore could not be exercised
as of December 31, 2001.
11 The "Value Realized" is ordinary income, before taxes, and represents the
amount equal to the excess of the fair market value of the shares at the time of
exercise above the exercise price.
III-5
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Pension Plan Table. The following table sets forth the estimated annual pension
benefits payable at normal retirement age under SOUTHERN's qualified Pension
Plan, as well as non-qualified supplemental benefits, based on the stated
compensation and years of service with the SOUTHERN system for Ms. Miller and
Messrs. Holland and James. Compensation for pension purposes is limited to the
average of the highest three of the final 10 years' compensation. Compensation
is base salary plus the excess of annual incentive compensation over 15 percent
of base salary. These compensation components are reported under columns titled
"Salary" and "Bonus" in the Summary Compensation Table on page III-3.
Years of Accredited Service
Remuneration 15 20 25 30 35 40
- ------------ -----------------------------------------------------------------
$ 100,000 $ 25,500 $ 34,000 $ 42,500 $ 51,000 $ 59,500 $ 68,000
300,000 76,500 102,000 127,500 153,000 178,500 204,000
500,000 127,500 170,000 212,500 255,000 297,500 340,000
700,000 178,500 238,000 297,500 357,000 416,500 476,000
900,000 229,500 306,000 382,500 459,000 535,500 612,000
1,100,000 280,500 374,000 467,500 561,000 654,500 748,000
1,300,000 331,500 442,000 552,500 663,000 773,500 884,000
As of December 31, 2001, the applicable compensation levels and years of
accredited service for SAVANNAH's named executive officers are presented in the
following table:
Compensation Accredited
Name Level Years of Service
G. Edison Holland, Jr.12 $522,288 18
Anthony R. James 299,112 22
W. Miles Greer13 250,600 25
Kirby R. Willis 235,192 27
Sandra R. Miller 156,036 21
The amounts shown in the table were calculated according to the final average
pay formula and are based on a single life annuity without reduction for joint
and survivor annuities or computation of Social Security offset that would apply
in most cases.
- -----------------------
12 The number of accredited years of service includes 9 years and 3 months
credited to Mr. Holland pursuant to a supplemental pension agreement.
13 The number of accredited years of service includes 7 years and 6 months
credited to Mr. Greer pursuant to a supplemental pension agreement.
III-6
Effective January 1, 1998, SAVANNAH merged its pension plan into the
SOUTHERN Pension Plan. SAVANNAH also has in effect a supplemental executive
retirement plan for certain of its executive employees. The plan is designed to
provide participants with a supplemental retirement benefit, which, in
conjunction with Social Security and benefits under SOUTHERN's qualified pension
plan, will equal 70 percent of the highest three of the final 10 years' average
annual earnings (excluding incentive compensation).
The following table sets forth the estimated combined annual pension
benefits under SOUTHERN's pension and SAVANNAH's supplemental executive
retirement plans in effect during 2001 which are payable to Messrs. Greer and
Willis, upon retirement at the normal retirement age after designated periods
of accredited service and at a specified compensation level.
Years of Accredited Service
Remuneration 15 25 35
- -------------------------- -- -- --
$150,000 105,000 105,000 105,000
180,000 126,000 126,000 126,000
210,000 147,000 147,000 147,000
260,000 182,000 182,000 182,000
280,000 196,000 196,000 196,000
300,000 210,000 210,000 210,000
350,000 245,000 245,000 245,000
400,000 280,000 280,000 280,000
430,000 301,000 301,000 301,000
460,000 322,000 322,000 322,000
Compensation of Directors.
Standard Arrangements. The following table presents compensation paid to
the directors during 2001 for service as a member of the board of directors and
any board committee(s), except that employee directors received no fees or
compensation for service as a member of the board of directors or any board
committee. At the election of the director, all or a portion of the cash
retainer may be payable in SOUTHERN's common stock, and all or a portion of the
total fees may be deferred under the Deferred Compensation Plan until membership
on the board is terminated.
Cash Retainer Fee $10,000
Stock Retainer Fee 50 shares in the first quarter 2001 and 85 shares per
quarter thereafter
Meeting Fees:
$750 for each Board or Committee meeting attended
Effective January 1, 1997, the Outside Directors Pension Plan (the "Plan")
was terminated and benefits payable under the Plan were frozen. Non-employee
directors serving as of January 1, 1997 were given a one-time election to
receive a Plan benefit buy-out equal to the actuarial present value of future
Plan benefits or receive benefits under the terms of the Plan at the annual
retainer rate in effect on December 31, 1996. Directors who elected to receive
the benefit buy-out were required to defer receipt of that amount under the
Deferred Compensation Plan until termination from board membership. Directors
who elected to continue to participate under the terms of the Plan are entitled
to benefits upon retirement from the board on the retirement date designated in
SAVANNAH's by-laws. The annual benefit payable is based upon length of service
and varies from 75 percent of the annual retainer in effect on December 31, 1996
if the participant has at least 60 months of service on the board of one or more
system companies, to 100 percent if the participant has at least 120 months of
such service. Payments will continue for the greater of the lifetime of the
participant or 10 years.
III-7
Other Arrangements. No director received other compensation for services as
a director during the year ending December 31, 2001 in addition to or in lieu of
that specified by the standard arrangements specified above.
Employment Contracts and Termination of Employment and Change in Control
Arrangements.
- ------------------------------------------------------------------------
SAVANNAH has adopted SOUTHERN's Change in Control Plan, which is applicable to
certain of its officers, and has entered into individual change in control
agreements with its most highly compensated executive officers. If an executive
is involuntarily terminated, other than for cause, within two years following a
change in control of SAVANNAH or SOUTHERN, the agreements provide for:
o lump sum payment of two or three times annual compensation,
o up to five years' coverage under group health and life insurance plans,
o immediate vesting of all stock options, stock appreciation rights and
restricted stock previously granted,
o payment of any accrued long-term and short-term bonuses and dividend
equivalents and
o payment of any excise tax liability incurred as a result of payments
made under any individual agreements.
A SOUTHERN change in control is defined under the agreements as:
o acquisition of at least 20 percent of the SOUTHERN's stock,
o a change in the majority of the members of the SOUTHERN's board of directors,
o a merger or other business combination that results in SOUTHERN's
shareholders immediately before the merger owning less than 65 percent of
the voting power after the merger or
o a sale of substantially all the assets of SOUTHERN.
A change in control of SAVANNAH is defined under the agreements as:
o acquisition of at least 50 percent of SAVANNAH's stock,
o a merger or other business combination unless SOUTHERN controls the
surviving entity or
o a sale of substantially all the assets of SAVANNAH.
SOUTHERN also has amended its short- and long-term incentive plans to
provide for pro-rata payments at not less than target-level performance if a
change in control occurs and the plans are not continued or replaced with
comparable plans.
Report on Repricing of Options.
None.
Compensation Committee Interlocks and Insider Participation.
None.
III-8
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security Ownership of Certain Beneficial Owners. SOUTHERN is the beneficial
owner of 100% of the outstanding common stock of SAVANNAH.
- -------------------------------------------------------------------------------
Amount and
Name and Address Nature of Percent
of Beneficial Beneficial of
Title of Class Owner Ownership Class
- -------------------------------------------------------------------------------
Common Stock The Southern Company 100%
270 Peachtree Street, N.W.
Atlanta, Georgia 30303
Registrant:
SAVANNAH 10,844,635
Security Ownership of Management. The following table shows the number of shares
of SOUTHERN common stock owned by the SAVANNAH's directors, nominees and
executive officers as of December 31, 2001. It is based on information furnished
by the directors, nominees and executive officers. The shares owned by all
directors, nominees and executive officers as a group constitute less than one
percent of the total number of shares outstanding on December 31, 2001.
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
- ------------------ -------------- --------------------------
Gus H. Bell, III SOUTHERN Common 259
Archie H. Davis SOUTHERN Common 522
Walter D. Gnann SOUTHERN Common 3,433
Anthony R. James SOUTHERN Common 43,854
Robert B. Miller, III SOUTHERN Common 1,128
Arnold M. Tenenbaum SOUTHERN Common 1,167
W. Miles Greer SOUTHERN Common 46,348
Sandra R. Miller SOUTHERN Common 3,365
Kirby R. Willis SOUTHERN Common 40,712
The directors, nominees
and executive officers
as a group SOUTHERN Common 140,788
(1) As used in this table, "beneficial ownership" means the sole or shared
power to vote, or to direct the voting of, a security and/or investment
power with respect to a security (i.e., the power to dispose of, or to
direct the disposition of, a security).
(2) The shares shown include shares of SOUTHERN common stock of which certain
directors and executive officers have the right to acquire beneficial
ownership within 60 days pursuant to the Executive Stock Plan and/or
Performance Stock Plan, as follows: Mr. Greer, 41,887 shares; Mr. James,
30,640 shares, Ms. Miller, 1,565 shares and Mr. Willis, 34,933 shares.
III-9
Changes in control. SOUTHERN and SAVANNAH know of no arrangements which may at a
subsequent date result in any change in control.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Transactions with management and others.
Mr. Archie Davis is currently Chief Executive Officer of The Savannah Bank,
N.A., Savannah, Georgia and was also President prior to February 2002. During
2001, this bank furnished a number of regular banking services in the ordinary
course of business to SAVANNAH. SAVANNAH intends to maintain normal banking
relations with the aforesaid bank in the future.
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
III-10
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this
Form 10-K:
(1) Financial Statements:
Reports of Independent Public Accountants on the financial statements
for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH are listed under Item 8 herein.
The financial statements filed as a part of this report for SOUTHERN
and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH are listed under Item 8 herein.
(2) Financial Statement Schedules:
Reports of Independent Public Accountants as to Schedules for SOUTHERN
and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH are included herein on pages IV-12 through IV-17.
Financial Statement Schedules for SOUTHERN and Subsidiary Companies,
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed in the
Index to the Financial Statement Schedules at page S-1.
(3) Exhibits:
Exhibits for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH are listed in the Exhibit Index at page E-1.
(b) Reports on Form 8-K during the fourth quarter of 2001 were as follows:
SOUTHERN filed a Current Report on Form 8-K:
Date of event: December 20, 2001
Items reported: Item 5
GEORGIA filed a Current Report on Form 8-K:
Date of event: December 20, 2001
Items reported: Item 5
GULF filed Current Reports on Form 8-K:
Date of event: October 5, 2001
Items reported: Items 5 and 7
Date of event: November 8, 2001
Items reported: Items 5 and 7
IV-1
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
THE SOUTHERN COMPANY
By: H. Allen Franklin, Chairman, President and
Chief Executive Officer
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
H. Allen Franklin
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
Gale E. Klappa
Executive Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
W. Dean Hudson
Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Daniel P. Amos L. G. Hardman III
Dorrit J. Bern Donald M. James
Thomas F. Chapman Zack T. Pate
Bruce S. Gordon Gerald J. St. Pe'
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
ALABAMA POWER COMPANY
By: Charles D. McCrary, President and
Chief Executive Officer
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Charles D. McCrary
President, Chief Executive Officer and Director
(Principal Executive Officer)
William B. Hutchins, III
Executive Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Art P. Beattie
Vice President and Comptroller
(Principal Accounting Officer)
Directors:
Whit Armstrong Mayer Mitchell
David J. Cooper William V. Muse
H. Allen Franklin Robert D. Powers
R. Kent Henslee C. Dowd Ritter
Patricia M. King James H. Sanford
James K. Lowder John Cox Webb, IV
Wallace D. Malone, Jr. James W. Wright
Thomas C. Meredith
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
IV-2
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
GEORGIA POWER COMPANY
By: David M. Ratcliffe, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
David M. Ratcliffe
President, Chief Executive Officer and Director
(Principal Executive Officer)
Thomas A. Fanning
Executive Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)
Cliff S. Thrasher
Vice President, Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Juanita P. Baranco James R. Lientz, Jr.
Anna R. Cablik Richard W. Ussery
William A. Fickling, Jr. William Jerry Vereen
H. Allen Franklin Carl Ware
L. G. Hardman III E. Jenner Wood, III
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
GULF POWER COMPANY
By: Travis J. Bowden, President and
Chief Executive Officer
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Travis J. Bowden
President, Chief Executive Officer and Director
(Principal Executive Officer)
Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
(Principal Financial and Accounting Officer)
Directors:
C. LeDon Anchors W. Deck Hull, Jr.
Fred C. Donovan, Sr. William A. Pullum
H. Allen Franklin Joseph K. Tannehill
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
IV-3
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
MISSISSIPPI POWER COMPANY
By: Michael D. Garrett, President and
Chief Executive Officer
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Michael D. Garrett
President, Chief Executive Officer and Director
(Principal Executive Officer)
Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Tommy E. Dulaney George A. Schloegel
Aubrey K. Lucas Gene Warr
Malcolm Portera
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
SAVANNAH ELECTRIC AND POWER COMPANY
By: Anthony R. James, President and
Chief Executive Officer
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Anthony R. James
President, Chief Executive Officer and Director
(Principal Executive Officer)
Kirby R. Willis
Vice President, Treasurer and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Gus H. Bell, III Robert B. Miller, III
Archie H. Davis Arnold M. Tenenbaum
Walter D. Gnann
/s/Wayne Boston
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 22, 2002
IV-4
Exhibit 21. Subsidiaries of the Registrants.*
Jurisdiction of
Name of Company Organization
- -------------------------------------------------------------------------------
The Southern Company Delaware
Southern Company Capital Trust I Delaware
Southern Company Capital Trust II Delaware
Southern Company Capital Trust III Delaware
Southern Company Capital Trust IV Delaware
Southern Company Capital Trust V Delaware
Southern Company Capital Trust VI Delaware
Southern Company Capital Trust VII Delaware
Southern Company Capital Trust VIII Delaware
Southern Company Capital Trust IX Delaware
Alabama Power Company Alabama
Alabama Power Capital Trust I Delaware
Alabama Power Capital Trust II Delaware
Alabama Power Capital Trust III Delaware
Alabama Power Capital Trust IV Delaware
Alabama Power Capital Trust V Delaware
Alabama Property Company Alabama
Southern Electric Generating Company Alabama
Georgia Power Company Georgia
Georgia Power Capital Trust I Delaware
Georgia Power Capital Trust II Delaware
Georgia Power Capital Trust III Delaware
Georgia Power Capital Trust IV Delaware
Georgia Power Capital Trust V Delaware
Georgia Power Capital Trust VI Delaware
Georgia Power Capital Trust VII Delaware
Georgia Power Capital Trust VIII Delaware
Piedmont-Forrest Corporation Georgia
Southern Electric Generating Company Alabama
Gulf Power Company Maine
Gulf Power Capital Trust I Delaware
Gulf Power Capital Trust II Delaware
Gulf Power Capital Trust III Delaware
Gulf Power Capital Trust IV Delaware
Mississippi Power Company Mississippi
Mississippi Power Capital Trust I Delaware
Mississippi Power Capital Trust II Delaware
Mississippi Power Capital Trust III Delaware
Savannah Electric and Power Company Georgia
Savannah Electric Capital Trust I Delaware
Savannah Electric Capital Trust II Delaware
Southern Power Company Delaware
- -------------------------------------------------------------------------------
*This information is as of December 31, 2001. In addition, this list omits
certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K, Item
601.
IV-5
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of The Southern Company and its subsidiaries and the related financial statement
schedule, included in this Form 10-K, into The Southern Company's previously
filed Registration Statement File Nos. 2-78617, 33-3546, 33-54415, 33-57951,
33-58371, 33-60427, 333-09077, 333-31808, 333-44127, 333-44261, 333-64871,
333-65178 and 333-73462.
/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002
IV-6
Exhibit 23(b)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Alabama Power Company and the related financial statement schedule, included
in this Form 10-K, into Alabama Power Company's previously filed Registration
Statement File No. 333-72784.
/s/Arthur Andersen LLP
Birmingham, Alabama
March 19, 2002
IV-7
Exhibit 23(c)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Georgia Power Company and the related financial statement schedule, included
in this Form 10-K, into Georgia Power Company's previously filed Registration
Statement File Nos. 333-75193 and 333-57884.
/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002
IV-8
Exhibit 23(d)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Gulf Power Company and the related financial statement schedule, included in
this Form 10-K, into Gulf Power Company's previously filed Registration
Statement File No. 333-59942.
/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002
IV-9
Exhibit 23(e)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Mississippi Power Company and the related financial statement schedule,
included in this Form 10-K, into Mississippi Power Company's previously filed
Registration Statement File No. 333-45069.
/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002
IV-10
Exhibit 23(f)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Savannah Electric and Power Company and the related financial statement
schedule, included in this Form 10-K, into Savannah Electric and Power Company's
previously filed Registration Statement File No. 333-57886.
/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002
IV-11
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To The Southern Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the consolidated financial statements of The Southern Company
and its subsidiaries included in this Form 10-K, and have issued our report
thereon dated February 13, 2002. Our audits were made for the purpose of forming
an opinion on those statements taken as a whole. The schedule listed under Item
14(a)(2) herein as it relates to The Southern Company and its subsidiaries (page
S-2) is the responsibility of The Southern Company's management and is presented
for purposes of complying with the Securities and Exchange Commission's rules
and is not part of the basic consolidated financial statements. This schedule
has been subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
IV-12
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Alabama Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Alabama Power Company included in
this Form 10-K, and have issued our report thereon dated February 13, 2002. Our
audits were made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed under Item 14(a)(2) herein as it relates to
Alabama Power Company (page S-3) is the responsibility of Alabama Power
Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 13, 2002
IV-13
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Georgia Power Company:
We have audited in accordance with auditing standards generally accepted
in the United States, the financial statements of Georgia Power Company included
in this Form 10-K, and have issued our report thereon dated February 13, 2002.
Our audits were made for the purpose of forming an opinion on those statements
taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates
to Georgia Power Company (page S-4) is the responsibility of Georgia Power
Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
IV-14
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Gulf Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Gulf Power Company included in
this Form 10-K, and have issued our report thereon dated February 13, 2002. Our
audits were made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Gulf
Power Company (page S-5) is the responsibility of Gulf Power Company's
management and is presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic financial statements.
This schedule has been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion, fairly states in
all material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
IV-15
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Mississippi Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Mississippi Power Company
included in this Form 10-K, and have issued our report thereon dated February
13, 2002. Our audits were made for the purpose of forming an opinion on those
statements taken as a whole. The schedule listed under Item 14(a)(2) herein as
it relates to Mississippi Power Company (page S-6) is the responsibility of
Mississippi Power Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
IV-16
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Savannah Electric and Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Savannah Electric and Power
Company included in this Form 10-K, and have issued our report thereon dated
February 13, 2002. Our audits were made for the purpose of forming an opinion on
those statements taken as a whole. The schedule listed under Item 14(a)(2)
herein as it relates to Savannah Electric and Power Company (page S-7) is the
responsibility of Savannah Electric and Power Company's management and is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule
II Valuation and Qualifying Accounts and Reserves
2001, 2000 and 1999
The Southern Company and Subsidiary Companies................... S-2
Alabama Power Company........................................... S-3
Georgia Power Company........................................... S-4
Gulf Power Company.............................................. S-5
Mississippi Power Company....................................... S-6
Savannah Electric and Power Company............................. S-7
Schedules I through V not listed above are omitted as not applicable or not
required. Columns omitted from schedules filed have been omitted because the
information is not applicable or not required.
S-1
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(Stated in Thousands of Dollars)
Additions
----------------------------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
-------------------------------- ------------------------ -------------- ------------------- ----------------- --------------
Provision for uncollectible
accounts
2001..................... $21,799 $44,272 $269 $41,957 (Note) $24,383
2000..................... 21,834 31,329 39 31,403 (Note) 21,799
1999..................... 11,268 35,476 - 24,910 (Note) 21,834
- -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-2
ALABAMA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(Stated in Thousands of Dollars)
Additions
---------------------------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
------------------------------------ ----------------------- --------------- ------------------ ----------------- ---------------
Provision for uncollectible
accounts
2001.......................... $6,237 $7,419 $- $8,419 (Note) $5,237
2000.......................... 4,117 9,093 - 6,973 (Note) 6,237
1999.......................... 1,855 13,995 - 11,733 (Note) 4,117
- -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-3
GEORGIA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(Stated in Thousands of Dollars)
Additions
---------------------------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
----------------------------------- ----------------------- -------------- ------------------ ----------------- ----------------
Provision for uncollectible
accounts
2001.......................... $5,100 $22,913 $- $19,118 (Note) $8,895
2000.......................... 7,000 10,794 - 12,694 (Note) 5,100
1999.......................... 5,500 14,406 - 12,906 (Note) 7,000
- -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-4
GULF POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(Stated in Thousands of Dollars)
Additions
--------------------------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
------------------------------------ ------------------------ --------------- ------------------ ---------------- ---------------
Provision for uncollectible
accounts
2001.......................... $1,302 $2,282 $- $2,242(Note) $1,342
2000.......................... 1,026 2,702 - 2,426(Note) 1,302
1999.......................... 996 2,230 - 2,200(Note) 1,026
- -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-5
MISSISSIPPI POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(Stated in Thousands of Dollars)
Additions
--------------------------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
------------------------------------ ------------------------- -------------- ------------------ ---------------- ---------------
Provision for uncollectible
accounts
2001.......................... $571 $2,877 $(165) $2,427 (Note) $856
2000.......................... 697 1,156 14 1,296 (Note) 571
1999.......................... 621 1,964 - 1,888 (Note) 697
- -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-6
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(Stated in Thousands of Dollars)
Additions
-------------------------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
-------------------------------------- ---------------------- ------------ ------------------ --------------- -----------------
Provision for uncollectible
accounts
2001.......................... $407 $978 $- $885 (Note) $500
2000.......................... 237 999 - 829 (Note) 407
1999.......................... 284 594 - 641 (Note) 237
- -------------------
Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously
written off.
S-7
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit number
are filed herewith. The balance of the exhibits have heretofore been filed with
the SEC as the exhibits and in the file numbers indicated and are incorporated
herein by reference. The exhibits marked with a pound sign are management
contracts or compensatory plans or arrangements required to be filed herewith
and required to be identified as such by Item 14 of Form 10-K. Reference is made
to a duplicate list of exhibits being filed as a part of this Form 10-K, which
list, prepared in accordance with Item 601 of Regulation S-K of the SEC,
immediately precedes the exhibits being physically filed with this Form 10-K.
(3) Articles of Incorporation and By-Laws
SOUTHERN
(a) 1 - Composite Certificate of Incorporation of SOUTHERN,
reflecting all amendments thereto through January 5, 1994.
(Designated in Registration No. 33-3546 as Exhibit 4(a), in
Certificate of Notification, File No. 70-7341, as Exhibit A
and in Certificate of Notification, File No. 70-8181, as
Exhibit A.)
(a) 2 - By-laws of SOUTHERN as amended effective October 21, 1991,
and as presently in effect. (Designated in Form U-1, File No.
70-8181, as Exhibit A-2.)
ALABAMA
(b) 1 - Charter of ALABAMA and amendments thereto through January
10, 2001. (Designated in Registration Nos. 2-59634 as Exhibit
2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b),
2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539
as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K
dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in
Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit
4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164,
as Exhibits 4(a) and 4(b), in Form 8-K dated November 16,
1993, File No. 1-3164, as Exhibit 4(a), in Certificate of
Notification, File No. 70-8191, as Exhibit A, in ALABAMA's
Form 10-K for the year ended December 31, 1997, File No.
1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998,
File No. 1-3164, as Exhibit 4.4 and in ALABAMA's Form 10-K for
the year ended December 31, 2000, File No. 1-3164, as Exhibit
3(b)2.)
*(b) 2 - Amendment to Charter of ALABAMA dated November 21,
2001.
*(b) 3 - By-laws of ALABAMA as amended effective April 26,
2001, and as presently in effect.
GEORGIA
(c) 1 - Charter of GEORGIA and amendments thereto through January
16, 2001. (Designated in Registration Nos. 2-63392 as Exhibit
2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as
Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit
4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit
4(b)(2), 33-
E-1
14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits
4(b)-(2), 4(b)-(3) and 4(b)-(4), in GEORGIA's Form 10-K for
the year ended December 31, 1991, File No. 1-6468, as Exhibits
4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits
4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992,
File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17,
1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated
October 20, 1993, File No. 1-6468, as Exhibit 4(b), in
GEORGIA's Form 10-K for the year ended December 31, 1997, File
No. 1-6468, as Exhibit 3(c)2 and in GEORGIA's Form 10-K for
the year ended December 31, 2000, File No. 1-6468, as Exhibit
3(c)2.)
(c) 2 - By-laws of GEORGIA as amended effective November 15, 2000,
and as presently in effect. (Designated in GEORGIA's Form 10-K
for the year ended December 31, 2000, File No. 1-6468, as
Exhibit 3(c)3.)
GULF
(d) 1 - Restated Articles of Incorporation of GULF and amendments
thereto through February 9, 2001. (Designated in Registration
No. 33-43739 as Exhibit 4(b)-1, in Form 8-K dated January 15,
1992, File No. 0-2429, as Exhibit 1(b), in Form 8-K dated
August 18, 1992, File No. 0-2429, as Exhibit 4(b)-2, in Form
8-K dated September 22, 1993, File No. 0-2429, as Exhibit 4,
in Form 8-K dated November 3, 1993, File No. 0-2429, as
Exhibit 4, in GULF's Form 10-K for the year ended December 31,
1997, File No. 0-2429, as Exhibit 3(d)2 and in GULF's Form
10-K for the year ended December 31, 2000, File No. 0-2429, as
Exhibit 3(d)2.)
*(d) 2 - By-laws of GULF as amended effective May 22, 2001, and
as presently in effect.
MISSISSIPPI
(e) 1 - Articles of Incorporation of MISSISSIPPI, articles of
merger of Mississippi Power Company (a Maine corporation) into
MISSISSIPPI and articles of amendment to the articles of
incorporation of MISSISSIPPI through March 8, 2001.
(Designated in Registration No. 2-71540 as Exhibit 4(a)-1, in
Form U5S for 1987, File No. 30-222-2, as Exhibit B-10, in
Registration No. 33-49320 as Exhibit 4(b)-(1), in Form 8-K
dated August 5, 1992, File No. 0-6849, as Exhibits 4(b)-2 and
4(b)-3, in Form 8-K dated August 4, 1993, File No. 0-6849, as
Exhibit 4(b)-3, in Form 8-K dated August 18, 1993, File No.
0-6849, as Exhibit 4(b)-3, in MISSISSIPPI's Form 10-K for the
year ended December 31, 1997, File No. 0-6849, as Exhibit
3(e)2 and in MISSISSIPPI's Form 10-K for the year ended
December 31, 2000, File No. 0-6849, as Exhibit 3(e)2.)
*(e) 2 - By-laws of MISSISSIPPI as amended effective February
28, 2001, and as presently in effect.
E-2
SAVANNAH
(f) 1 - Charter of SAVANNAH and amendments thereto through
December 2, 1998. (Designated in Registration Nos. 33-25183 as
Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2), in Form 8-K
dated November 9, 1993, File No. 1-5072, as Exhibit 4(b) and
in SAVANNAH's Form 10-K for the year ended December 31, 1998,
as Exhibit 3(f)2.)
(f) 2 - By-laws of SAVANNAH as amended effective May 17, 2000, and
as presently in effect. (Designated in SAVANNAH's Form 10-K
for the year ended December 31, 2000, File No. 1-5072, as
Exhibit 3(f)2.)
(4) Instruments Describing Rights of Security Holders, Including Indentures
SOUTHERN
(a) 1 - Subordinated Note Indenture dated as of February 1, 1997,
among SOUTHERN, Southern Company Capital Funding, Inc. and
Bankers Trust Company, as Trustee, and indentures supplemental
thereto dated as of February 4, 1997. (Designated in
Registration Nos. 333-28349 as Exhibits 4.1 and 4.2 and
333-28355 as Exhibit 4.2.)
(a) 2 - Subordinated Note Indenture dated as of June 1, 1997,
among SOUTHERN, Southern Company Capital Funding, Inc. and
Bankers Trust Company, as Trustee, and indentures supplemental
thereto through December 23, 1998. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1997, File No.
1-3526, as Exhibit (4)(a)2, in Form 8-K dated June 18, 1998,
File No. 1-3526, as Exhibit 4.2 and in Form 8-K dated December
18, 1998, File No. 1-3526, as Exhibit 4.4.)
(a) 3 - Senior Note Indenture dated as of February 1, 2002, among
SOUTHERN, Southern Company Capital Funding, Inc. and The Bank
of New York, as Trustee, and indentures supplemental thereto
through those dated February 1, 2002. (Designated in Form 8-K
dated January 29, 2002, File No. 1-3526, as Exhibits 4.1 and
4.2 and in Form 8-K dated January 30, 2002, File No. 1-3526,
as Exhibit 4.2.)
(a) 4 - Amended and Restated Trust Agreement of Southern Company
Capital Trust I dated as of February 1, 1997. (Designated in
Registration No. 333-28349 as Exhibit 4.6)
(a) 5 - Amended and Restated Trust Agreement of Southern Company
Capital Trust II dated as of February 1, 1997. (Designated in
Registration No. 333-28355 as Exhibit 4.6)
(a) 6 - Amended and Restated Trust Agreement of Southern Company
Capital Trust III dated as of June 1, 1997. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1997,
File No. 1-3526, as Exhibit (4)(a)5.)
(a) 7 - Amended and Restated Trust Agreement of Southern Company
Capital Trust IV dated as of June 1, 1998. (Designated in Form
8-K dated June 18, 1998, File No. 1-3526, as Exhibit 4.5.)
E-3
(a) 8 - Amended and Restated Trust Agreement of Southern Company
Capital Trust V dated as of December 1, 1998. (Designated in
Form 8-K dated December 18, 1998, File No. 1-3526, as Exhibit
4.7A.)
(a) 9 - Capital Securities Guarantee Agreement relating to
Southern Company Capital Trust I dated as of February 1, 1997.
(Designated in Registration No. 333-28349 as Exhibit 4.10)
(a) 10 - Capital Securities Guarantee Agreement relating to
Southern Company Capital Trust II dated as of February 1,
1997. (Designated in Registration No. 333-28355 as Exhibit
4.10)
(a) 11 - Preferred Securities Guarantee Agreement relating to
Southern Company Capital Trust III dated as of June 1, 1997.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1997, File No. 1-3526, as Exhibit (4)(a)8.)
(a) 12 - Preferred Securities Guarantee Agreement relating to
Southern Company Capital Trust IV dated as of June 1, 1998.
(Designated in Form 8-K dated June 18, 1998, File No. 1-3626,
as Exhibit 4.8.)
(a) 13 - Preferred Securities Guarantee Agreement relating to
Southern Company Capital Trust V dated as of December 1, 1998.
(Designated in Form 8-K dated December 18, 1998, File No.
1-3526, as Exhibit 4.11A.)
ALABAMA
(b) 1 - Indenture dated as of January 1, 1942, between ALABAMA and
JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as
Trustee, and indentures supplemental thereto through December
1, 1994. (Designated in Registration Nos. 2-59843 as Exhibit
2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as
Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit
2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2,
2-73727 as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083
as Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in ALABAMA's
Form 10-K for the year ended December 31, 1990, File No.
1-3164, as Exhibit 4(c), in Registration Nos. 33-43917 as
Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as
Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated
January 20, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form
8-K dated February 17, 1993, File No. 1-3164, as Exhibit
4(a)-3, in Form 8-K dated March 10, 1993, File No. 1-3164, as
Exhibit 4(a)-3, in Certificate of Notification, File No.
70-8069, as Exhibits A and B, in Form 8-K dated June 24, 1993,
File No. 1-3164, as Exhibit 4, in Certificate of Notification,
File No. 70-8069, as Exhibit A, in Form 8-K dated November 16,
1993, File No. 1-3164, as Exhibit 4(b), in Certificate of
Notification, File No. 70-8069, as Exhibits A and B, in
Certificate of Notification, File No. 70-8069, as Exhibit A,
in Certificate of Notification, File No. 70-8069, as Exhibit A
and in Form 8-K dated November 30, 1994, File No. 1-3164, as
Exhibit 4.)
E-4
(b) 2 - Subordinated Note Indenture dated as of January 1, 1996,
between ALABAMA and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indenture supplemental
thereto dated as of January 1, 1996. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibits E
and F.)
(b) 3 - Subordinated Note Indenture dated as of January 1, 1997,
between ALABAMA and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through February 25, 1999. (Designated in Form 8-K
dated January 9, 1997, File No. 1-3164, as Exhibits 4.1 and
4.2 and in Form 8-K dated February 18, 1999, File No. 3164, as
Exhibit 4.2.)
(b) 4 - Senior Note Indenture dated as of December 1, 1997,
between ALABAMA and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through August 29, 2001. (Designated in Form 8-K dated
December 4, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in
Form 8-K dated February 20, 1998, File No. 1-3164, as Exhibit
4.2, in Form 8-K dated April 17, 1998, File No. 1-3164, as
Exhibit 4.2, in Form 8-K dated August 11, 1998, File No.
1-3164, as Exhibit 4.2, in Form 8-K dated September 8, 1998,
File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September
16, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated
October 7, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K
dated October 28, 1998, File No. 1-3164, as Exhibit 4.2, in
Form 8-K dated November 12, 1998, File No. 1-3164, as Exhibit
4.2, in Form 8-K dated May 19, 1999, File No. 1-3164, as
Exhibit 4.2, in Form 8-K dated August 13, 1999, File No.
1-3164, as Exhibit 4.2, in Form 8-K dated September 21, 1999,
File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 11,
2000, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated
August 22, 2001, File No. 1-3164, as Exhibits 4.2(a) and
4.2(b).)
(b) 5 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust I dated as of January 1, 1996. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit D.)
(b) 6 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust II dated as of January 1, 1997. (Designated in
Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibit
4.5.)
(b) 7 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust III dated as of February 1, 1999. (Designated in
Form 8-K dated February 18, 1999, File No. 1-3164, as Exhibit
4.5.)
(b) 8 - Guarantee Agreement relating to Alabama Power Capital
Trust I dated as of January 1, 1996. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit G.)
(b) 9 - Guarantee Agreement relating to Alabama Power Capital
Trust II dated as of January 1, 1997. (Designated in Form 8-K
dated January 9, 1997, File No. 1-3164, as Exhibit 4.8.)
(b) 10 - Guarantee Agreement relating to Alabama Power Capital
Trust III dated as of February 1, 1999. (Designated in Form
8-K dated February 18, 1999, File No. 1-3164, as Exhibit 4.8.)
E-5
GEORGIA
(c) 1 - Indenture dated as of March 1, 1941, between GEORGIA and
JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as
Trustee, and indentures supplemental thereto dated as of March
1, 1941, March 3, 1941 (3 indentures), March 6, 1941 (139
indentures), March 1, 1946 (88 indentures) and December 1,
1947, through October 15, 1995. (Designated in Registration
Nos. 2-4663 as Exhibits B-3 and B-3(a), 2-7299 as Exhibit
7(a)-2, 2-61116 as Exhibit 2(a)-3 and 2(a)-4, 2-62488 as
Exhibit 2(a)-3, 2-63393 as Exhibit 2(a)-4, 2-63705 as Exhibit
2(a)-3, 2-68973 as Exhibit 2(a)-3, 2-70679 as Exhibit
4(a)-(2), 2-72324 as Exhibit 4(a)-2, 2-73987 as Exhibit
4(a)-(2), 2-77941 as Exhibits 4(a)-(2) and 4(a)-(3), 2-79336
as Exhibit 4(a)-(2), 2-81303 as Exhibit 4(a)-(2), 2-90105 as
Exhibit 4(a)-(2), 33-5405 as Exhibit 4(a)-(2), 33-14367 as
Exhibits 4(a)-(2) and 4(a)-(3), 33-22504 as Exhibits 4(a)-(2),
4(a)-(3) and 4(a)-(4), 33-32420 as Exhibit 4(a)-(2), 33-35683
as Exhibit 4(a)-(2), in GEORGIA's Form 10-K for the year ended
December 31, 1990, File No. 1-6468, as Exhibit 4(a)(3), in
Form 10-K for the year ended December 31, 1991, File No.
1-6468, as Exhibit 4(a)(5), in Registration No. 33-48895 as
Exhibit 4(a)-(2), in Form 8-K dated August 26, 1992, File No.
1-6468, as Exhibit 4(a)-(3), in Form 8-K dated September 9,
1992, File No. 1-6468, as Exhibits 4(a)-(3) and 4(a)-(4), in
Form 8-K dated September 23, 1992, File No. 1-6468, as Exhibit
4(a)-(3), in Form 8-A dated October 12, 1992, as Exhibit 2(b),
in Form 8-K dated January 27, 1993, File No. 1-6468, as
Exhibit 4(a)-(3), in Registration No. 33-49661 as Exhibit
4(a)-(2), in Form 8-K dated July 26, 1993, File No. 1-6468, as
Exhibit 4, in Certificate of Notification, File No. 70-7832,
as Exhibit M, in Certificate of Notification, File No.
70-7832, as Exhibit C, in Certificate of Notification, File
No. 70-7832, as Exhibits K and L, in Certificate of
Notification, File No. 70-8443, as Exhibit C, in Certificate
of Notification, File No. 70-8443, as Exhibit C, in
Certificate of Notification, File No. 70-8443, as Exhibit E,
in Certificate of Notification, File No. 70-8443, as Exhibit
E, in Certificate of Notification, File No. 70-8443, as
Exhibit E, in GEORGIA's Form 10-K for the year ended December
31, 1994, File No. 1-6468, as Exhibits 4(c)2 and 4(c)3, in
Certificate of Notification, File No. 70-8443, as Exhibit C,
in Certificate of Notification, File No. 70-8443, as Exhibit
C, in Form 8-K dated May 17, 1995, File No. 1-6468, as Exhibit
4 and in GEORGIA's Form 10-K for the year ended December 31,
1995, File No. 1-6468, as Exhibits 4(c)2, 4(c)3, 4(c)4, 4(c)5
and 4(c)6.)
*(c) 2 - Satisfaction and Discharge of Indenture, Release and
Deed of Reconveyance dated as of February 27, 2002, by
JPMorgan Chase Bank, as Trustee, to GEORGIA relating to the
defeasance of the Indenture dated as of March 1, 1941 between
GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan
Bank), as Trustee, and indentures supplemental thereto through
October 15, 1995.
(c) 3 - Subordinated Note Indenture dated as of August 1, 1996,
between GEORGIA and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through January 1, 1997. (Designated in Form 8-K dated
August 21, 1996, File No. 1-6468, as Exhibits 4.1 and 4.2 and
in Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit
4.2.)
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(c) 4 - Subordinated Note Indenture dated as of June 1, 1997,
between GEORGIA and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through February 25, 1999. (Designated in Certificate
of Notification, File No. 70-8461, as Exhibits D and E and
Form 8-K dated February 17, 1999, File No. 1-6468, as Exhibit
4.4.)
(c) 5 - Senior Note Indenture dated as of January 1, 1998, between
GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan
Bank), as Trustee, and indentures supplemental thereto through
May 8, 2001. (Designated in Form 8-K dated January 21, 1998,
File No. 1-6468, as Exhibits 4.1 and 4.2, in Forms 8-K each
dated November 19, 1998, File No. 1-6468, as Exhibit 4.2, in
Form 8-K dated March 3, 1999, File No. 1-6469 as Exhibit 4.2,
in Form 8-K dated February 15, 2000, File No. 1-6469 as
Exhibit 4.2, in Form 8-K dated January 26, 2001, File No.
1-6469 as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated
February 16, 2001, File No. 1-6469 as Exhibit 4.2 and in Form
8-K dated May 1, 2001, File No. 1-6468, as Exhibit 4.2.)
(c) 6 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust I dated as of August 1, 1996. (Designated in
Form 8-K dated August 21, 1996, File No. 1-6468, as Exhibit
4.5.)
(c) 7 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust II dated as of January 1, 1997. (Designated in
Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit
4.5.)
(c) 8 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust III dated as of June 1, 1997. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit C.)
(c) 9 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust IV dated as of February 1, 1999. (Designated in
Form 8-K dated February 17, 1999, as Exhibit 4.7-A)
(c) 10 - Guarantee Agreement relating to Georgia Power Capital
Trust I dated as of August 1, 1996. (Designated in Form 8-K
dated August 21, 1996, File No. 1-6468, as Exhibit 4.8.)
(c) 11 - Guarantee Agreement relating to Georgia Power Capital
Trust II dated as of January 1, 1997. (Designated in Form 8-K
dated January 9, 1997, File No. 1-6468, as Exhibit 4.8.)
(c) 12 - Guarantee Agreement relating to Georgia Power Capital
Trust III dated as of June 1, 1997. (Designated in Certificate
of Notification, File No. 70-8461, as Exhibit F.)
(c) 13 - Guarantee Agreement relating to Georgia Power Capital
Trust IV dated as of February 1, 1999. (Designated in Form 8-K
dated February 17, 1999, as Exhibit 4.11-A.)
E-7
GULF
(d) 1 - Indenture dated as of September 1, 1941, between GULF and
JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as
Trustee, and indentures supplemental thereto through November
1, 1996. (Designated in Registration Nos. 2-4833 as Exhibit
B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as Exhibit 2(a)-3,
2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2, 33-43739
as Exhibit 4(a)-2, in GULF's Form 10-K for the year ended
December 31, 1991, File No. 0-2429, as Exhibit 4(b), in Form
8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(a)-3,
in Registration No. 33-50165 as Exhibit 4(a)-2, in Form 8-K
dated July 12, 1993, File No. 0-2429, as Exhibit 4, in
Certificate of Notification, File No. 70-8229, as Exhibit A,
in Certificate of Notification, File No. 70-8229, as Exhibits
E and F, in Form 8-K dated January 17, 1996, File No. 0-2429,
as Exhibit 4, in Certificate of Notification, File No.
70-8229, as Exhibit A, in Certificate of Notification, File
No. 70-8229, as Exhibit A and in Form 8-K dated November 6,
1996, File No. 0-2429, as Exhibit 4.)
(d) 2 - Subordinated Note Indenture dated as of January 1, 1997,
between GULF and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through November 16, 2001. (Designated in Form 8-K
dated January 27, 1997, File No. 0-2429, as Exhibits 4.1 and
4.2, in Form 8-K dated July 28, 1997, File No. 0-2429, as
Exhibit 4.2, in Form 8-K dated January 13, 1998, File No.
0-2429, as Exhibit 4.2 and in Form 8-K dated November 8, 2001,
File No. 0-2429, as Exhibit 4.2.)
(d) 3 - Senior Note Indenture dated as of January 1, 1998, between
GULF and JPMorgan Chase Bank (formerly The Chase Manhattan
Bank), as Trustee, and indentures supplemental thereto through
January 30, 2002. (Designated in Form 8-K dated June 17, 1998,
File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated
August 17, 1999, File No. 0-2429, as Exhibit 4.2, in Form 8-K
dated July 31, 2001, File No. 0-2429, as Exhibit 4.2, in Form
8-K dated October 5, 2001, File No. 0-2429, as Exhibit 4.2 and
in Form 8-K dated January 18, 2002, File No. 0-2429, as
Exhibit 4.2.)
(d) 4 - Amended and Restated Trust Agreement of Gulf Power Capital
Trust I dated as of January 1, 1997. (Designated in Form 8-K
dated January 27, 1997, File No. 0-2429, as Exhibit 4.5.)
(d) 5 - Amended and Restated Trust Agreement of Gulf Power Capital
Trust II dated as of January 1, 1998. (Designated in Form 8-K
dated January 13, 1998, File No. 0-2429, as Exhibit 4.5.)
(d) 6 - Amended and Restated Trust Agreement of Gulf Power Capital
Trust III dated as of November 1, 2001. (Designated in Form
8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.5.)
(d) 7 - Guarantee Agreement relating to Gulf Power Capital Trust I
dated as of January 1, 1997. (Designated in Form 8-K dated
January 27, 1997, File No. 0-2429, as Exhibit 4.8.)
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(d) 8 - Guarantee Agreement relating to Gulf Power Capital Trust
II dated as of January 1, 1998. (Designated in Form 8-K dated
January 13, 1998, File No. 0-2429, as Exhibit 4.8.)
(d) 9 - Guarantee Agreement relating to Gulf Power Capital Trust
III dated as of November 1, 2001. (Designated in Form 8-K
dated November 8, 1998, File No. 0-2429, as Exhibit 4.8.)
MISSISSIPPI
(e) 1 - Indenture dated as of September 1, 1941, between
MISSISSIPPI and Bankers Trust Company, as Successor Trustee,
and indentures supplemental thereto through December 1, 1995.
(Designated in Registration Nos. 2-4834 as Exhibit B-3,
2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2, 2-71537
as Exhibit 4(a)-(2), 33-5414 as Exhibit 4(a)-(2), 33-39833 as
Exhibit 4(a)-2, in MISSISSIPPI's Form 10-K for the year ended
December 31, 1991, File No. 0-6849, as Exhibit 4(b), in Form
8-K dated August 5, 1992, File No. 0-6849, as Exhibit 4(a)-2,
in Second Certificate of Notification, File No. 70-7941, as
Exhibit I, in MISSISSIPPI's Form 8-K dated February 26, 1993,
File No. 0-6849, as Exhibit 4(a)-2, in Certificate of
Notification, File No. 70-8127, as Exhibit A, in Form 8-K
dated June 22, 1993, File No. 0-6849, as Exhibit 1, in
Certificate of Notification, File No. 70-8127, as Exhibit A,
in Form 8-K dated March 8, 1994, File No. 0-6849, as Exhibit
4, in Certificate of Notification, File No. 70-8127, as
Exhibit C and in Form 8-K dated December 5, 1995, File No.
0-6849, as Exhibit 4.)
(e) 2 - Senior Note Indenture dated as of May 1, 1998 between
MISSISSIPPI and Bankers Trust Company, as Trustee and
indentures supplemental thereto through March 28, 2000.
(Designated in Form 8-K dated May 14, 1998, File No. 0-6849,
as Exhibits 4.1, 4.2(a) and 4.2(b) and in Form 8-K dated March
22, 2000, File No. 0-6849, as Exhibit 4.2.)
(e) 3 - Subordinated Note Indenture dated as of February 1, 1997,
between MISSISSIPPI and Bankers Trust Company, as Trustee, and
indenture supplemental thereto dated as of February 1, 1997.
(Designated in Form 8-K dated February 20, 1997, File No.
0-6849, as Exhibits 4.1 and 4.2.)
(e) 4 - Amended and Restated Trust Agreement of Mississippi Power
Capital Trust I dated as of February 1, 1997. (Designated in
Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibit
4.5.)
(e) 5 - Guarantee Agreement relating to Mississippi Power Capital
Trust I dated as of February 1, 1997. (Designated in Form 8-K
dated February 20, 1997, File No. 0-6849, as Exhibit 4.8.)
SAVANNAH
(f) 1 - Indenture dated as of March 1, 1945, between SAVANNAH and
The Bank of New York, as Trustee, and indentures supplemental
thereto through May 1, 1996. (Designated in Registration Nos.
33-25183 as Exhibit 4(a)-(1), 33-41496 as Exhibit 4(a)-(2),
33-45757 as Exhibit 4(a)-(2), in SAVANNAH's Form 10-K for
E-9
the year ended December 31, 1991, File No. 1-5072, as Exhibit
4(b), in Form 8-K dated July 8, 1992, File No. 1-5072, as
Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit
4(a)-(2), in Form 8-K dated July 22, 1993, File No. 1-5072, as
Exhibit 4, in Form 8-K dated May 18, 1995, File No. 1-5072, as
Exhibit 4 and in Form 8-K dated May 23, 1996, File No. 1-5072,
as Exhibit 4.)
(f) 2 - Senior Note Indenture dated as of March 1, 1998 between
SAVANNAH and The Bank of New York, as Trustee and indentures
supplemental thereto through May 17, 2001. (Designated in Form
8-K dated March 9, 1998, File No. 1-5072, as Exhibits 4.1 and
4.2 and in Form 8-K dated May 8, 2001, File No. 1-5072, as
Exhibits 4.2(a) and 4.2(b).)
(f) 3 - Subordinated Note Indenture dated as of December 1, 1998,
between SAVANNAH and The Bank of New York, as Trustee, and
indenture supplemental thereto dated as of December 9, 1998.
(Designated in Form 8-K dated December 3, 1998, File No.
1-5072, as Exhibit 4.3 and 4.4.)
(f) 4 - Amended and Restated Trust Agreement of Savannah Electric
Capital Trust I dated as of December 1, 1998. (Designated in
Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit
4.7.)
(f) 5 - Guarantee Agreement relating to Savannah Electric Capital
Trust I dated as of December 1, 1998. (Designated in Form 8-K
dated December 3, 1998, File No. 1-5072, as Exhibit 4.11.)
(10) Material Contracts
SOUTHERN
(a) 1 - Service contracts dated as of January 1, 1984, between SCS
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
and Amendment No. 1 dated as of September 6, 1985 between SCS
and SOUTHERN. (Designated in SOUTHERN's Form 10-K for the year
ended December 31, 1984, File No. 1-3526, as Exhibit 10(a) and
in SOUTHERN's Form 10-K for the year ended December 31, 1985,
File No. 1-3526, as Exhibit 10(a)(3).)
*(a) 2 - Service contract dated as of January 1, 2001, between
SCS and Southern Power.
(a) 3 - Service contract dated as of March 3, 1988, between SCS
and SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year
ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.)
(a) 4 - Service contract dated as of January 15, 1991, between SCS
and Southern Nuclear. (Designated in SOUTHERN's Form 10-K for
the year ended December 31, 1991, File No. 1-3526, as Exhibit
10(a)(4).)
(a) 5 - Service contract dated as of December 12, 1994, between
SCS and Mobile Energy Services Company, Inc. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1994,
File No. 1-3526, as Exhibit 10(a)58.)
E-10
(a) 6 - Interchange contract dated February 17, 2000, between
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)6.)
(a) 7 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
ALABAMA and GEORGIA. (Designated in Registration No. 2-59634
as Exhibit 5(c), in GEORGIA's Form 10-K for the year ended
December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2) and in
ALABAMA's Form 10-K for the year ended December 31, 1994, File
No. 1-3164, as Exhibit 10(b)18.)
(a) 8 - Joint Committee Agreement dated as of August 27, 1976,
among GEORGIA, OPC, MEAG and Dalton. (Designated in
Registration No. 2-61116 as Exhibit 5(d).)
(a) 9 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of January 6, 1975, between
GEORGIA and OPC. (Designated in Form 8-K for January, 1975,
File No. 1-6468, as Exhibit (b)(1).)
(a) 10 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of January 6, 1975, between GEORGIA and OPC. (Designated in
Form 8-K for January, 1975, File No. 1-6468, as Exhibit
(b)(3).)
(a) 11 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between GEORGIA and
OPC. (Designated in GEORGIA's Form 10-K for the year ended
December 31, 1990, File No. 1-6468, as Exhibit 10(g).)
(a) 12 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of March 26, 1976, between GEORGIA and OPC.
(Designated in Certificate of Notification, File No. 70-5592,
as Exhibit A.)
(a) 13 - Plant Hal Wansley Operating Agreement dated as of March
26, 1976, between GEORGIA and OPC. (Designated in Certificate
of Notification, File No. 70-5592, as Exhibit B.)
(a) 14 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of August 27, 1976, between
GEORGIA, MEAG and Dalton. (Designated in Form 8-K dated as of
June 13, 1977, File No. 1-6468, as Exhibit (b)(1).)
(a) 15 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of August 27, 1976, between GEORGIA, MEAG and Dalton.
(Designated in Form 8-K for February 1977, File No. 1-6468, as
Exhibit (b)(2).)
(a) 16 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
and Ownership Participation Agreement dated as of August 27,
1976 and Amendment No. 1 dated as of January 18, 1977, among
GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File
No. 70-5792, as Exhibit B-1 and in Form 8-K for January 1977,
File No. 1-6468, as Exhibit (B)(3).)
E-11
(a) 17 - Alvin W. Vogtle Nuclear Units Number One and Two
Operating Agreement dated as of August 27, 1976, among
GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File
No. 70-5792, as Exhibit B-2.)
(a) 18 - Alvin W. Vogtle Nuclear Units Number One and Two
Purchase, Amendment, Assignment and Assumption Agreement dated
as of November 16, 1983, between GEORGIA and MEAG. (Designated
in GEORGIA's Form 10-K for the year ended December 31, 1983,
File No. 1-6468, as Exhibit 10(k)(4).)
(a) 19 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of August 27, 1976, between GEORGIA and
MEAG. (Designated in Form 8-K dated as of July 5, 1977, File
No. 1-6468, as Exhibit (b)(2).)
(a) 20 - Plant Hal Wansley Operating Agreement dated as of August
27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K
dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(4).)
(a) 21 - Nuclear Operating Agreement between Southern Nuclear and
GEORGIA dated as of July 1, 1993. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1997, File No.
1-3526, as Exhibit 10(a)21.)
(a) 22 - Pseudo Scheduling and Services Agreement between GEORGIA
and MEAG dated as of April 8, 1997. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1997, File No.
1-3526, as Exhibit 10(a)22.)
(a) 23 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of April 19, 1977, between GEORGIA and
Dalton. (Designated in Form 8-K dated as of June 13, 1977,
File No. 1-6468, as Exhibit (b)(3).)
(a) 24 - Plant Hal Wansley Operating Agreement dated as of April
19, 1977, between GEORGIA and Dalton. (Designated in Form 8-K
dated as of June 13, 1977, File No. 1-6468, as Exhibit
(b)(7).)
(a) 25 - Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement dated as of May 15,
1980, Amendment No. 1 dated as of December 30, 1985, Amendment
No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of
August 1, 1988 and Amendment No. 4 dated as of December 31,
1990, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form
U-1, File No. 70-6481, as Exhibit B-3, in SOUTHERN's Form 10-K
for the year ended December 31, 1987, File No. 1-3526, as
Exhibit 10(o)(2), in SOUTHERN's Form 10-K for the year ended
December 31, 1989, File No. 1-3526, as Exhibit 10(n)(2) and in
SOUTHERN's Form 10-K for the year ended December 31, 1993,
File No. 1-3526, as Exhibit 10(a)54.)
(a) 26 - Plant Robert W. Scherer Units Number One and Two
Operating Agreement dated as of May 15, 1980, Amendment No. 1
dated as of December 3, 1985 and Amendment No. 2 dated as of
December 31, 1990, among GEORGIA, OPC, MEAG and Dalton.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-4, in
SOUTHERN's Form 10-K for the year ended December 31, 1987,
File No. 1-3526, as Exhibit 10(o)(4) and in SOUTHERN's Form
10-K for the year ended December 31, 1993, File No. 1-3526, as
Exhibit 10(a)55.)
E-12
(a) 27 - Plant Robert W. Scherer Purchase, Sale and Option
Agreement dated as of May 15, 1980, between GEORGIA and MEAG.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-1.)
(a) 28 - Plant Robert W. Scherer Purchase and Sale Agreement dated
as of May 16, 1980, between GEORGIA and Dalton. (Designated in
Form U-1, File No. 70-6481, as Exhibit B-2.)
(a) 29 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1, 1984,
Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
dated as of August 1, 1988, between GEORGIA and GULF.
(Designated in Form U-1, File No. 70-6573, as Exhibit B-4, in
SOUTHERN's Form 10-K for the year ended December 31, 1987, as
Exhibit 10(o)(2) and in SOUTHERN's Form 10-K for the year
ended December 31, 1989, as Exhibit 10(n)(2).)
(a) 30 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between GEORGIA and GULF.
(Designated in Form U-1, File No. 70-6573, as Exhibit B-5.)
(a) 31 - Plant Robert W. Scherer Unit No. Four Amended and
Restated Purchase and Ownership Participation Agreement by and
among GEORGIA, FP&L and JEA, dated as of December 31, 1990 and
Amendment No. 1 dated as of June 15, 1994. (Designated in Form
U-1, File No. 70-7843, as Exhibit B-1 and in SOUTHERN's Form
10-K for the year ended December 31, 1994, File No. 1-3526, as
Exhibit 10(a)60.)
(a) 32 - Plant Robert W. Scherer Unit No. Four Operating Agreement
by and among GEORGIA, FP&L and JEA, dated as of December 31,
1990 and Amendment No. 1 dated as of June 15, 1994.
(Designated in Form U-1, File No. 70-7843, as Exhibit B-2 and
in SOUTHERN's Form 10-K for the year ended December 31, 1994,
File No. 1-3526, as Exhibit 10(a)61.)
(a) 33 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
(Designated in SAVANNAH's Form 10-K for the year ended
December 31, 1988, File No. 1-5072, as Exhibit 10(d).)
(a) 34 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. (Designated in SAVANNAH's Form 10-K for the year
ended December 31, 1988, File No. 1-5072, as Exhibit 10(e).)
(a) 35 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. (Designated in SAVANNAH's Form 10-K for the year
ended December 31, 1988, File No. 1-5072, as Exhibit 10(f).)
(a) 36 - Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement dated November 18, 1988,
between OPC and GEORGIA. (Designated in GEORGIA's Form 10-K
for the year ended December 31, 1988, File No. 1-6468, as
Exhibit 10(x).)
E-13
(a) 37 - Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement dated November 18, 1988, between OPC and
GEORGIA. (Designated in GEORGIA's Form 10-K for the year ended
December 31, 1988, File No. 1-6468, as Exhibit 10(y).)
(a) 38 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric Generating
Plant Units One and Two dated November 18, 1988, between
ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as
Exhibit B-1.)
(a) 39 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant Units One
and Two dated November 18, 1988, between ALABAMA and AEC.
(Designated in Form U-1, File No. 70-7609, as Exhibit B-2.)
(a) 40 - Transmission Facilities Agreement dated February 25,
1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2
dated December 6, 1983, between Gulf States and MISSISSIPPI.
(Designated in MISSISSIPPI's Form 10-K for the year ended
December 31, 1981, File No. 0-6849, as Exhibit 10(f), in
MISSISSIPPI's Form 10-K for the year ended December 31, 1982,
File No. 0-6849, as Exhibit 10(f)(2) and in MISSISSIPPI's Form
10-K for the year ended December 31, 1983, File No. 0-6849, as
Exhibit 10(f)(3).)
(a) 41 - Long Term Transaction Service Agreement between GEORGIA
and OPC dated as of February 26, 1999. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1999,
File No. 1-3526, as Exhibit 10(a)46.)
(a) 42 - Revised and Restated Coordination Services Agreement
between and among GEORGIA, OPC and Georgia Systems Operations
Corporation dated as of September 10, 1997. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1997,
File No. 1-3526, as Exhibit 10(a)48.)
(a) 43 - Amended and Restated Nuclear Managing Board Agreement for
Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and
Dalton dated as of July 1, 1993. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1993, File No.
1-3526, as Exhibit 10(a)49.)
(a) 44 - Integrated Transmission System Agreement, Power Sale and
Coordination Umbrella Agreement between GEORGIA and OPC dated
as of November 12, 1990. (Designated in GEORGIA's Form 10-K
for the year ended December 31, 1990, File No. 1-6468, as
Exhibit 10(ff).)
(a) 45 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and Dalton dated as of December 7,
1990. (Designated in GEORGIA's Form 10-K for the year ended
December 31, 1990, File No. 1-6468, as Exhibit 10(gg).)
(a) 46 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and MEAG dated as of December 7,
1990. (Designated in GEORGIA's Form 10-K for the year ended
December 31, 1990, File No. 1-6468, as Exhibit 10(hh).)
E-14
(a) 47 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and ALABAMA, MISSISSIPPI and SCS. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1992,
File No. 1-3526, as Exhibit 10(a)53.)
(a) 48 - Plant Scherer Managing Board Agreement dated as of
December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L
and JEA. (Designated in SOUTHERN's Form 10-K for the year
ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)56.)
(a) 49 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between GEORGIA and SAVANNAH dated as
of December 15, 1992. (Designated in SOUTHERN's Form 10-K for
the year ended December 31, 1993, File No. 1-3526, as Exhibit
10(a)57.)
(a) 50 - Plant McIntosh Combustion Turbine Operating Agreement
between GEORGIA and SAVANNAH dated as of December 15, 1992.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1993, File No. 1-3526, as Exhibit 10(a)58.)
(a) 51 - Operating Agreement for the Joseph M. Farley Nuclear
Plant between ALABAMA and Southern Nuclear dated as of
December 23, 1991. (Designated in Form U-1, File No. 70-7530,
as Exhibit B-7.)
*(a) 52 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 2002.
*(a) 53 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002.
# (a) 54 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. (Designated in
Form S-8, File No. 333-73462, as Exhibit 4(c).)
# (a) 55 - The Deferred Compensation Plan for the Directors of
The Southern Company, Amended and Restated effective February
19, 2001. (Designated in SOUTHERN's Form 10-K for the year
ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)59.)
# (a) 56 - The Southern Company Outside Directors Pension Plan.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1994, File No. 1-3526, as Exhibit 10(a)77.)
# (a) 57 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective February 23, 2001. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)61.)
# (a) 58 - The Southern Company Outside Directors Stock Plan and
First Amendment thereto. (Designated in Registration No.
33-54415 as Exhibit 4(c) and in SOUTHERN's Form 10-K for the
year ended December 31, 1995, File No. 1-3526, as Exhibit
10(a)79.)
E-15
# (a) 59 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)63.)
(a) 60 - The Southern Company Pension Plan, effective as of
January 1, 1997 and all amendments thereto through Amendment
Number Six. (Designated in SOUTHERN's Form 10-K for the year
ended December 31, 1996, File No. 1-3526, as Exhibit 10(a)83,
in SOUTHERN's Form 10-K for the year ended December 31, 1997,
File No. 1-3526, as Exhibit 10(a)79, in SOUTHERN's Form 10-K
for the year ended December 31, 1998, File No. 1-3526 as
Exhibit 10(a)71, in SOUTHERN's Form 10-K for the year ended
December 31, 1999, File No. 1-3526, as Exhibit 10(a)72 and in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526 as Exhibit 10(a)66.)
*(a) 61 - Amendment Number Seven to The Southern Company
Pension Plan.
#*(a) 62 - The Southern Company Supplemental Executive
Retirement Plan, Amended and Restated effective May 1, 2000.
#*(a) 63 - The Southern Company Performance Sharing Plan,
Amended and Restated effective January 1, 2002.
#*(a) 64 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective May 1, 2000.
(a) 65 - Southern Company Change in Control Severance Plan,
Amended and Restated effective July 10, 2000. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)72.)
# (a) 66 - Southern Company Executive Change in Control
Severance Plan, Amended and Restated effective July 10, 2000.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)73.)
# (a) 67 - Deferred Compensation Agreement between SOUTHERN,
Southern Nuclear and William G. Hairston III. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1998,
File No. 1-3526 as Exhibit 10(a)81.)
# (a) 68 - Deferred Compensation Agreement between SOUTHERN,
GEORGIA and Warren Y. Jobe. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1998, File No. 1-3526 as
Exhibit 10(a)82.)
# (a) 69 - Amended and Restated Change in Control Agreement
between SOUTHERN, GULF and Travis J. Bowden. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)79.)
# (a) 70 - Amended and Restated Change in Control Agreement
between SOUTHERN, SCS and A. W. Dahlberg. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)80.)
E-16
# (a) 71 - Amended and Restated Change in Control Agreement
between SOUTHERN, MISSISSIPPI and Dwight H. Evans. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)81.)
# (a) 72 - Amended and Restated Change in Control Agreement
between SOUTHERN, SCS and Henry Allen Franklin. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)83.)
# (a) 73 - Amended and Restated Change in Control Agreement
between SOUTHERN, Southern Nuclear and William G. Hairston,
III. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)84.)
# (a) 74 - Amended and Restated Change in Control Agreement
between SOUTHERN, ALABAMA and Elmer B. Harris. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)85.)
# (a) 75 - Amended and Restated Change in Control Agreement
between SOUTHERN, SAVANNAH and G. Edison Holland, Jr.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)86.)
# (a) 76 - Amended and Restated Change in Control Agreement
between SOUTHERN, SCS and C. Alan Martin. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)87.)
# (a) 77 - Amended and Restated Change in Control Agreement
between SOUTHERN, SCS and Charles Douglas McCrary. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)88.)
# (a) 78 - Amended and Restated Change in Control Agreement
between SOUTHERN, GEORGIA and David M. Ratcliffe. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)89.)
# (a) 79 - Amended and Restated Change in Control Agreement
between SOUTHERN, SCS and Stephen A. Wakefield. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)90.)
# (a) 80 - Amended and Restated Change in Control Agreement
between SOUTHERN, SCS and W. Lawrence Westbrook. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)91.)
# (a) 81 - Amended and Restated Change in Control Agreement
between SOUTHERN, SCS and Gale E. Klappa. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)92.)
# (a) 82 - Deferred Compensation Agreement between SOUTHERN and
William L. Westbrook. (Designated in SOUTHERN's Form 10-K for
the year ended December 31, 2000, File No. 1-3526, as Exhibit
10(a)94.)
#*(a) 83 - First Amendment to Deferred Compensation Agreement
between SOUTHERN and William L. Westbrook dated September 7,
2001.
E-17
# (a) 84 - Deferred Compensation Agreement between SOUTHERN and
Alfred W. Dahlberg, III. (Designated in SOUTHERN's Form 10-K
for the year ended December 31, 2000, File No. 1-3526, as
Exhibit 10(a)95.)
# (a) 85 - Southern Company Change in Control Benefit Plan
Determination Policy, effective July 10, 2000. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)96.)
# (a) 86 - Change in Control Agreement between SOUTHERN, SCS and
Robert H. Haubein, Jr. (Designated in SOUTHERN's Form 10-K for
the year ended December 31, 2000, File No. 1-3526, as Exhibit
10(a)97.)
# (a) 87 - Master Separation and Distribution Agreement dated as
of September 1, 2000 between SOUTHERN and Mirant. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 2000,
File No. 1-3526, as Exhibit 10(a)100.)
# (a) 88 - Indemnification and Insurance Matters Agreement dated
as of September 1, 2000 between SOUTHERN and Mirant.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)101.)
# (a) 89 - Tax Indemnification Agreement dated as of September
1, 2000 among SOUTHERN and its affiliated companies and Mirant
and its affiliated companies. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 2000, File No. 1-3526, as
Exhibit 10(a)102.)
# (a) 90 - Southern Company Deferred Compensation Trust
Agreement dated as of January 1, 2001 between Wachovia Bank,
N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH, Southern Communications, Energy Solutions, Mirant
and Southern Nuclear. (Designated in SOUTHERN's Form 10-K for
the year ended December 31, 2000, File No. 1-3526, as Exhibit
10(a)103.)
# (a) 91 - Deferred Stock Trust Agreement for Directors of
SOUTHERN and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SAVANNAH. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 2000, File No. 1-3526, as
Exhibit 10(a)104.)
#*(a) 92 - Amended and Restated Deferred Cash Compensation
Trust Agreement for Directors of SOUTHERN and its
subsidiaries, effective September 1, 2001, between Wachovia
Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH.
ALABAMA
(b) 1 - Service contracts dated as of January 1, 1984, between SCS
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
and Amendment No. 1 dated as of September 6, 1985 between SCS
and SOUTHERN. See Exhibit 10(a)1 herein.
E-18
(b) 2 - Interchange contract dated February 17, 2000, between
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
See Exhibit 10(a)6 herein.
(b) 3 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.
(b) 4 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)33 herein.
(b) 5 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)34 herein.
(b) 6 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)35 herein.
(b) 7 - Firm Power Purchase Contract between ALABAMA and AMEA.
(Designated in Certificate of Notification, File No. 70-7212,
as Exhibit B.)
(b) 8 - 1991 Firm Power Purchase Contract between ALABAMA and
AMEA. (Designated in Form U-1, File No. 70-7873, as Exhibit
B-1.)
(b) 9 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric Generating
Plant Units One and Two dated November 18, 1988, between
ALABAMA and AEC. See Exhibit 10(a)38 herein.
(b) 10 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant Units One
and Two dated November 18, 1988, between ALABAMA and AEC. See
Exhibit 10(a)39 herein.
(b) 11 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit
10(a)47 herein.
(b) 12 - Operating Agreement for the Joseph M. Farley Nuclear
Plant between ALABAMA and Southern Nuclear dated as of
December 23, 1991. See Exhibit 10(a)51 herein.
*(b) 13 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 2002. See Exhibit 10(a)52
herein.
*(b) 14 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)53 herein.
# (b) 15 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)54 herein.
# (b) 16 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective February 23, 2001. See Exhibit
10(a)57 herein.
E-19
# (b) 17 - The Southern Company Outside Directors Pension Plan.
See Exhibit 10(a)56 herein.
# (b) 18 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)59 herein.
(b) 19 - The Southern Company Pension Plan, effective as of
January 1, 1997 and all amendments thereto through Amendment
Number Six. See Exhibit 10(a)60 herein.
*(b) 20 - Amendment Number Seven to The Southern Company
Pension Plan. See Exhibit 10(a)61 herein.
#*(b) 21 - The Southern Company Supplemental Executive Retirement
Plan, Amended and Restated effective May 1, 2000. See Exhibit
10(a)62 herein.
#*(b) 22 - The Southern Company Performance Sharing Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)63 herein.
#*(b) 23 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective May 1, 2000. See Exhibit
10(a)64 herein.
(b) 24 - Southern Company Change in Control Severance Plan,
Amended and Restated effective July 10, 2000. See Exhibit
10(a)65 herein.
# (b) 25 - Southern Company Executive Change in Control
Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)66 herein.
#*(b) 26 - Deferred Compensation Agreement between ALABAMA and
Elmer B. Harris.
# (b) 27 - Supplemental Pension Agreement between ALABAMA, GULF
and Travis J. Bowden. (Designated in ALABAMA's Form 10-K for
the year ended December 31, 1998, File No. 1-3164, as Exhibit
10(b)40.)
#*(b) 28 - Deferred Compensation Plan for Directors of Alabama
Power Company, Amended and Restated effective January 1, 2001.
# (b) 29 - Southern Company Change in Control Benefit Plan
Determination Policy, effective July 10, 2000. See Exhibit
10(a)85 herein.
# (b) 30 - Southern Company Deferred Compensation Trust
Agreement dated as of January 1, 2001 between Wachovia Bank,
N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH, Southern Communications, Energy Solutions, Mirant
and Southern Nuclear. See Exhibit 10(a)90 herein.
# (b) 31 - Deferred Stock Trust Agreement for Directors of
SOUTHERN and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(b)91 herein.
E-20
#*(b) 32 - Amended and Restated Deferred Cash Compensation
Trust Agreement for Directors of SOUTHERN and its
subsidiaries, dated as of September 1, 2001, between Wachovia
Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH. See Exhibit 10(a)92 herein.
GEORGIA
(c) 1 - Service contracts dated as of January 1, 1984, between SCS
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
and Amendment No. 1 dated as of September 6, 1985, between SCS
and SOUTHERN. See Exhibit 10(a)1 herein.
(c) 2 - Interchange contract dated February 17, 2000, between
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
See Exhibit 10(a)6 herein.
(c) 3 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.
(c) 4 - Joint Committee Agreement dated as of August 27, 1976,
among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)8
herein.
(c) 5 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of January 6, 1975, between
GEORGIA and OPC. See Exhibit 10(a)9 herein.
(c) 6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of January 6, 1975, between GEORGIA and OPC. See Exhibit
10(a)10 herein.
(c) 7 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between GEORGIA and
OPC. See Exhibit 10(a)11 herein.
(c) 8 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of March 26, 1976, between GEORGIA and OPC.
See Exhibit 10(a)12 herein.
(c) 9 - Plant Hal Wansley Operating Agreement dated as of March
26, 1976, between GEORGIA and OPC. See Exhibit 10(a)13 herein.
(c) 10 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of August 27, 1976, between
GEORGIA, MEAG and Dalton. See Exhibit 10(a)14 herein.
(c) 11 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of August 27, 1976, between GEORGIA, MEAG and Dalton. See
Exhibit 10(a)15 herein.
(c) 12 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
and Ownership Participation Agreement dated as of August 27,
1976 and Amendment No. 1 dated as of January 18, 1977, among
GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)16 herein.
E-21
(c) 13 - Alvin W. Vogtle Nuclear Units Number One and Two
Operating Agreement dated as of August 27, 1976, among
GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)17 herein.
(c) 14 - Alvin W. Vogtle Nuclear Units Number One and Two
Purchase, Amendment, Assignment and Assumption Agreement dated
as of November 16, 1983, between GEORGIA and MEAG. See Exhibit
10(a)18 herein.
(c) 15 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of August 27, 1976, between GEORGIA and
MEAG. See Exhibit 10(a)19 herein.
(c) 16 - Plant Hal Wansley Operating Agreement dated as of August
27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)20
herein.
(c) 17 - Nuclear Operating Agreement between Southern Nuclear and
GEORGIA dated as of July 1, 1993. See Exhibit 10(a)21 herein.
(c) 18 - Pseudo Scheduling and Services Agreement between GEORGIA
and MEAG dated as of April 8, 1997. See Exhibit 10(a)22
herein.
(c) 19 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of April 19, 1977, between GEORGIA and
Dalton. See Exhibit 10(a)23 herein.
(c) 20 - Plant Hal Wansley Operating Agreement dated as of April
19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)24
herein.
(c) 21 - Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement dated as of May 15,
1980, Amendment No. 1 dated as of December 30, 1985, Amendment
No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of
August 1, 1988 and Amendment No. 4 dated as of December 31,
1990, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)25
herein.
(c) 22 - Plant Robert W. Scherer Units Number One and Two
Operating Agreement dated as of May 15, 1980, Amendment No. 1
dated as of December 3, 1985 and Amendment No. 2 dated as of
December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. See
Exhibit 10(a)26 herein.
(c) 23 - Plant Robert W. Scherer Purchase, Sale and Option
Agreement dated as of May 15, 1980, between GEORGIA and MEAG.
See Exhibit 10(a)27 herein.
(c) 24 - Plant Robert W. Scherer Purchase and Sale Agreement dated
as of May 16, 1980, between GEORGIA and Dalton. See Exhibit
10(a)28 herein.
(c) 25 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1, 1984,
Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
dated as of August 1, 1988, between GEORGIA and GULF. See
Exhibit 10(a)29 herein.
(c) 26 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between GEORGIA and GULF.
See Exhibit 10(a)30 herein.
E-22
(c) 27 - Plant Robert W. Scherer Unit No. Four Amended and
Restated Purchase and Ownership Participation Agreement by and
among GEORGIA, FP&L and JEA dated as of December 31, 1990 and
Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)31
herein.
(c) 28 - Plant Robert W. Scherer Unit No. Four Operating Agreement
by and among GEORGIA, FP&L and JEA dated as of December 31,
1990 and Amendment No. 1 dated as of June 15, 1994. See
Exhibit 10(a)32 herein.
(c) 29 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)33 herein.
(c) 30 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)34 herein.
(c) 31 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)35 herein.
(c) 32 - Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement dated November 18, 1988,
between OPC and GEORGIA. See Exhibit 10(a)36 herein.
(c) 33 - Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement dated November 18, 1988, between OPC and
GEORGIA. See Exhibit 10(a)37 herein.
(c) 34 - Long Term Transaction Service Agreement between GEORGIA
and OPC dated as of February 26, 1999. See Exhibit 10(a)41
herein.
(c) 35 - Revised and Restated Coordination Services Agreement
between and among GEORGIA, OPC and Georgia Systems Operations
Corporation dated as of September 10, 1997. See Exhibit
10(a)42 herein.
(c) 36 - Amended and Restated Nuclear Managing Board Agreement for
Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and
Dalton dated as of July 1, 1993. See Exhibit 10(a)43 herein.
(c) 37 - Integrated Transmission System Agreement, Power Sale and
Coordination Umbrella Agreement between GEORGIA and OPC dated
as of November 12, 1990. See Exhibit 10(a)44 herein.
(c) 38 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and Dalton dated as of December 7,
1990. See Exhibit 10(a)45 herein.
(c) 39 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and MEAG dated as of December 7,
1990. See Exhibit 10(a)46 herein.
E-23
(c) 40 - Plant Scherer Managing Board Agreement dated as of
December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L
and JEA. See Exhibit 10(a)48 herein.
(c) 41 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between GEORGIA and SAVANNAH dated as
of December 15, 1992. See Exhibit 10(a)49 herein.
(c) 42 - Plant McIntosh Combustion Turbine Operating Agreement
between GEORGIA and SAVANNAH dated as of December 15, 1992.
See Exhibit 10(a)50 herein.
*(c) 43 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 2002. See Exhibit 10(a)52
herein.
*(c) 44 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)53 herein.
# (c) 45 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)54 herein.
# (c) 46 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective February 23, 2001. See Exhibit
10(a)57 herein.
# (c) 47 - The Southern Company Outside Directors Pension Plan.
See Exhibit 10(a)56 herein.
# (c) 48 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)59 herein.
(c) 49 - The Southern Company Pension Plan, effective as of
January 1, 1997 and all amendments thereto through Amendment
Number Six. See Exhibit 10(a)60 herein.
*(c) 50 - Amendment Number Seven to The Southern Company
Pension Plan. See Exhibit 10(a)61 herein.
#*(c) 51 - The Southern Company Supplemental Executive
Retirement Plan, Amended and Restated effective May 1, 2000.
See Exhibit 10(a)62 herein.
#*(c) 52 - The Southern Company Performance Sharing Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)63 herein.
#*(c) 53 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective May 1, 2000. See Exhibit
10(a)64 herein.
(c) 54 - Southern Company Change in Control Severance Plan,
Amended and Restated effective July 10, 2000. See Exhibit
10(a)65 herein.
# (c) 55 - Southern Company Executive Change in Control
Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)66 herein.
E-24
# (c) 56 - Deferred Compensation Agreement between SOUTHERN,
GEORGIA and Warren Y. Jobe. See Exhibit 10(a)68 herein.
# (c) 57 - Amended and Restated Change in Control Agreement
between SOUTHERN, GEORGIA and David M. Ratcliffe. See Exhibit
10(a)78 herein.
# (c) 58 - Supplemental Pension Agreement between GEORGIA and
Warren Y. Jobe. (Designated in GEORGIA's Form 10-K for the
year ended December 31, 1998, File No. 1-6468, as Exhibit
10(c)77.)
#*(c) 59 - Separation Agreement between GEORGIA and Robert H.
Haubein, Jr. dated December 21, 2001 and First Amendment
thereto effective December 21, 2001.
#*(c) 60 - Separation Agreement between GEORGIA and Fred D.
Williams dated December 31, 2001.
# (c) 61 - Deferred Compensation Plan For Directors of Georgia
Power Company, Amended and Restated Effective February 21,
2001. (Designated in GEORGIA's Form 10-K for the year ended
December 31, 2000, File No. 1-6468 as Exhibit 10(c)71
# (c) 62 - Southern Company Change in Control Benefit Plan
Determination Policy, effective July 10, 2000. See Exhibit
10(a)85 herein.
# (c) 63 - Southern Company Deferred Compensation Trust
Agreement dated as of January 1, 2001 between Wachovia Bank,
N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH, Southern Communications, Energy Solutions, Mirant
and Southern Nuclear. See Exhibit 10(a)90 herein.
# (c) 64 - Deferred Stock Trust Agreement for Directors of
SOUTHERN and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.
#*(c) 65 - Amended and Restated Deferred Cash Compensation
Trust Agreement for Directors of SOUTHERN and its
subsidiaries, dated as of September 1, 2001, between Wachovia
Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH. See Exhibit 10 (a)92 herein.
GULF
(d) 1 - Service contracts dated as of January 1, 1984, between SCS
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
and Amendment No. 1 dated as of September 6, 1985, between SCS
and SOUTHERN. See Exhibit 10(a)1 herein.
(d) 2 - Interchange contract dated February 17, 2000, between
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
See Exhibit 10(a)6 herein.
E-25
(d) 3 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1, 1984,
Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
dated as of August 1, 1988, between GEORGIA and GULF. See
Exhibit 10(a)29 herein.
(d) 4 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between GEORGIA and GULF.
See Exhibit 10(a)30 herein.
(d) 5 - Plant Scherer Managing Board Agreement dated as of
December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L
and JEA. See Exhibit 10(a)48 herein.
(d) 6 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)33 herein.
(d) 7 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)34 herein.
(d) 8 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)35 herein.
(d) 9 - Agreement between GULF and AEC, effective August 1, 1985.
(Designated in GULF's Form 10-K for the year ended December
31, 1985, File No. 0-2429, as Exhibit 10(g).)
*(d) 10 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 2002. See Exhibit 10(a)52
herein.
*(d) 11 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)53 herein.
# (d) 12 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)54 herein.
# (d) 13 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective February 23, 2001. See Exhibit
10(a)57 herein.
# (d) 14 - The Southern Company Outside Directors Pension Plan.
See Exhibit 10(a)56 herein.
# (d) 15 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)59 herein.
(d) 16 - The Southern Company Pension Plan, effective as of
January 1, 1997 and all amendments thereto through Amendment
Number Six. See Exhibit 10(a)60 herein.
*(d) 17 - Amendment Number Seven to The Southern Company
Pension Plan. See Exhibit 10(a)61 herein.
E-26
#*(d) 18 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective May 1, 2000. See Exhibit
10(a)64 herein.
(d) 19 - Southern Company Change in Control Severance Plan,
Amended and Restated effective July 10, 2000. See Exhibit
10(a)65 herein.
# (d) 20 - Southern Company Executive Change in Control
Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)66 herein.
# (d) 21 - Amended and Restated Change in Control Agreement
between SOUTHERN, GULF and Travis J. Bowden. See Exhibit
10(a)69 herein.
#*(d) 22 - The Southern Company Supplemental Executive
Retirement Plan, Amended and Restated effective May 1, 2000.
See Exhibit 10(a)62 herein.
#*(d) 23 - The Southern Company Performance Sharing Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)63 herein.
# (d) 24 - Supplemental Pension Agreement between SAVANNAH, GULF
and G. Edison Holland, Jr. (Designated in GULF's Form 10-K for
the year ended December 31, 1998, File No. 0-2429, as Exhibit
10(d)35.)
# (d) 25 - Supplemental Pension Agreement between ALABAMA, GULF
and Travis J. Bowden. See Exhibit 10(b)27 herein.
# (d) 26 - Deferred Compensation Plan For Directors of Gulf
Power Company, Amended and Restated Effective January 1, 2000
and First Amendment thereto. (Designated in GULF's Form 10-K
for the year ended December 31, 2000, File No. 0-2429 as
Exhibit 10(d)33.)
# (d) 27 - Southern Company Change in Control Benefit Plan
Determination Policy, effective July 10, 2000. See Exhibit
10(a)85 herein.
# (d) 28 - Southern Company Deferred Compensation Trust
Agreement dated as of January 1, 2001 between Wachovia Bank,
N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH, Southern Communications, Energy Solutions, Mirant
and Southern Nuclear. See Exhibit 10(a)90 herein.
# (d) 29 - Deferred Stock Trust Agreement for Directors of
SOUTHERN and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.
#*(d) 30 - Amended and Restated Deferred Cash Compensation
Trust Agreement for Directors of SOUTHERN and its
subsidiaries, dated as of September 1, 2001, between Wachovia
Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH. See Exhibit 10(a)92 herein.
E-27
MISSISSIPPI
(e) 1 - Service contracts dated as of January 1, 1984, between SCS
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
and Amendment No. 1 dated as of September 6, 1985, between SCS
and SOUTHERN. See Exhibit 10(a)1 herein.
(e) 2 - Interchange contract dated February 17, 2000, between
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
See Exhibit 10(a)6 herein.
(e) 3 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)33 herein.
(e) 4 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)34 herein.
(e) 5 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)35 herein.
(e) 6 - Transmission Facilities Agreement dated February 25, 1982,
Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated
December 6, 1983, between Gulf States and MISSISSIPPI. See
Exhibit 10(a)40 herein.
(e) 7 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit
10(a)47 herein.
*(e) 8 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 2002. See Exhibit 10(a)52
herein.
*(e) 9 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)53 herein.
# (e) 10 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)54 herein.
# (e) 11 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective February 23, 2001. See Exhibit
10(a)57 herein.
# (e) 12 - The Southern Company Outside Directors Pension Plan.
See Exhibit 10(a)56 herein.
# (e) 13 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)59 herein.
(e) 14 - The Southern Company Pension Plan, effective as of
January 1, 1997 and all amendments thereto through Amendment
Number Six. See Exhibit 10(a)60 herein.
E-28
*(e) 15 - Amendment Number Seven to The Southern Company
Pension Plan. See Exhibit 10(a)61 herein.
#*(e) 16 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective May 1, 2000. See Exhibit
10(a)64 herein.
(e) 17 - Southern Company Change in Control Severance Plan,
Amended and Restated effective July 10, 2000. See Exhibit
10(a)65 herein.
# (e) 18 - Southern Company Executive Change in Control
Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)66 herein.
# (e) 19 - Amended and Restated Change in Control Agreement
between SOUTHERN, MISSISSIPPI and Dwight H. Evans. See Exhibit
10(a)71 herein.
#*(e) 20 - The Southern Company Supplemental Executive
Retirement Plan, Amended and Restated effective May 1, 2000.
See Exhibit 10(a)62 herein.
#*(e) 21 - The Southern Company Performance Sharing Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)63 herein.
# (e) 22 - Deferred Compensation Plan for Directors of
Mississippi Power Company, Amended and Restated Effective
January 1, 2000 and Amendment Number One thereto. (Designated
in MISSISSIPPI's Form 10-K for the year ended December 31,
1999, File No. 0-6849 as Exhibit 10(e)37 and in MISSISSIPPI'S
Form 10-K for the year December 31, 2000, File No. 0-6849 as
Exhibit 10(e)30.)
# (e) 23 - Southern Company Change in Control Benefit Plan
Determination Policy, effective July 10, 2000. See Exhibit
10(a)85 herein.
# (e) 24 - Southern Company Deferred Compensation Trust
Agreement dated as of January 1, 2001 between Wachovia Bank,
N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH, Southern Communications, Energy Solutions, Mirant
and Southern Nuclear. See Exhibit 10(a)90 herein.
# (e) 25 - Deferred Stock Trust Agreement for Directors of
SOUTHERN and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.
#*(e) 26 - Amended and Restated Deferred Cash Compensation
Trust Agreement for Directors of SOUTHERN and its
subsidiaries, dated as of September 1, 2001, between Wachovia
Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH. See Exhibit 10(a)92 herein.
SAVANNAH
(f) 1 - Service contract dated as of March 3, 1988, between SCS
and SAVANNAH. See Exhibit 10(a)3 herein.
E-29
(f) 2 - Interchange contract dated February 17, 2000, between
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
See Exhibit 10(a)6 herein.
(f) 3 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)33 herein.
(f) 4 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)34 herein.
(f) 5 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
and SCS. See Exhibit 10(a)35 herein.
(f) 6 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between GEORGIA and SAVANNAH dated as
of December 15, 1992. See Exhibit 10(a)49 herein.
(f) 7 - Plant McIntosh Combustion Turbine Operating Agreement
between GEORGIA and SAVANNAH dated December 15, 1992. See
Exhibit 10(a)50 herein.
*(f) 8 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 2002. See Exhibit 10(a)52
herein.
*(f) 9 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)53 herein.
# (f) 10 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)54 herein.
# (f) 11 - Supplemental Executive Retirement Plan of SAVANNAH,
Amended and Restated effective October 26, 2000. (Designated
in SAVANNAH's Form 10-K for the year ended December 31, 2000,
File No. 1-5072 as Exhibit 10(f)13.)
# (f) 12 - Deferred Compensation Plan for Key Employees of
SAVANNAH, Amended and Restated effective October 26, 2000.
(Designated in SAVANNAH's Form 10-K for the year ended
December 31, 2000, File No. 1-5072 as Exhibit 10(f)14.)
# (f) 13 - The Southern Company Outside Directors Pension Plan.
See Exhibit 10(a)56 herein.
# (f) 14 - Deferred Compensation Plan for Directors of SAVANNAH,
Amended and Restated effective October 26, 2000. (Designated
in SAVANNAH's Form 10-K for the year ended December 31, 2000,
File No. 1-5072 as Exhibit 10(f)18.)
# (f) 15 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)59 herein.
(f) 16 - The Southern Company Pension Plan, effective as of
January 1, 1997 and all amendments thereto through Amendment
Number Six. See Exhibit 10(a)60 herein.
E-30
*(f) 17 - Amendment Number Seven to The Southern Company
Pension Plan. See Exhibit 10(a)61 herein.
#*(f) 18 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective May 1, 2000. See Exhibit
10(a)64 herein.
(f) 19 - Southern Company Change in Control Severance Plan,
Amended and Restated effective July 10, 2000. See Exhibit
10(a)65 herein.
# (f) 20 - Southern Company Executive Change in Control
Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)66 herein.
# (f) 21 - Amended and Restated Change in Control Agreement
between SOUTHERN, SAVANNAH and G. Edison Holland, Jr. See
Exhibit 10(a)75 herein.
# (f) 22 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective February 23, 2001. See Exhibit
10(a)57 herein.
#*(f) 23 - The Southern Company Supplemental Executive
Retirement Plan, Amended and Restated effective May 1, 2000.
See Exhibit 10(a)62 herein.
#*(f) 24 - The Southern Company Performance Sharing Plan,
Amended and Restated effective January 1, 2002. See Exhibit
10(a)63 herein.
# (f) 25 - Supplemental Pension Agreement between SAVANNAH, GULF
and G. Edison Holland, Jr. See Exhibit 10(d)24 herein.
# (f) 26 - Southern Company Change in Control Benefit Plan
Determination Policy, effective July 10, 2000. See Exhibit
10(a)85 herein.
# (f) 27 - Agreement for supplemental pension benefits between
SAVANNAH and William Miles Greer. (Designated in SAVANNAH's
Form 10-K for the year ended December 31, 2000, File No.
1-5072 as Exhibit 10(f)34.)
# (f) 28 - Agreement crediting additional service between
SAVANNAH and William Miles Greer. (Designated in SAVANNAH's
Form 10-K for the year ended December 31, 2000, File No.
1-5072 as Exhibit 10(f)35.)
# (f) 29 - Southern Company Deferred Compensation Trust
Agreement dated as of January 1, 2001 between Wachovia Bank,
N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH, Southern Communications, Energy Solutions, Mirant
and Southern Nuclear. See Exhibit 10(a)90 herein.
# (f) 30 - Deferred Stock Trust Agreement for Directors of
SOUTHERN and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.
E-31
#*(f) 31 - Amended and Restated Deferred Cash Compensation
Trust Agreement for Directors of SOUTHERN and its
subsidiaries, dated as of September 1, 2001, between Wachovia
Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH. See Exhibit 10(a)92 herein.
(21) Subsidiaries of Registrants
SOUTHERN
*(a) - Subsidiaries of Registrant is contained herein at page IV-5.
ALABAMA
*(b) - Subsidiaries of Registrant is contained herein at page IV-5.
GEORGIA
*(c) - Subsidiaries of Registrant is contained herein at page IV-5.
GULF
*(d) - Subsidiaries of Registrant is contained herein at page IV-5.
MISSISSIPPI
*(e) - Subsidiaries of Registrant is contained herein at page IV-5.
SAVANNAH
*(f) - Subsidiaries of Registrant is contained herein at page IV-5.
(23) Consents of Experts and Counsel
SOUTHERN
*(a) - The consent of Arthur Andersen LLP is contained herein
at page IV-6.
ALABAMA
*(b) - The consent of Arthur Andersen LLP is contained herein
at page IV-7.
GEORGIA
*(c) - The consent of Arthur Andersen LLP is contained herein
at page IV-8.
GULF
*(d) - The consent of Arthur Andersen LLP is contained herein
at page IV-9.
E-32
MISSISSIPPI
*(e) - The consent of Arthur Andersen LLP is contained herein
at page IV-10.
SAVANNAH
*(f) - The consent of Arthur Andersen LLP is contained herein
at page IV-11.
(24) Powers of Attorney and Resolutions
SOUTHERN
*(a) - Power of Attorney and resolution.
ALABAMA
*(b) - Power of Attorney and resolution.
GEORGIA
*(c) - Power of Attorney and resolution.
GULF
*(d) - Power of Attorney and resolution.
MISSISSIPPI
*(e) - Power of Attorney and resolution.
SAVANNAH
*(f) - Power of Attorney and resolution.
E-33