===============================================================================
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, 2000
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
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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 6.85% Trust Preferred Securities10
Preferred Securities9
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1 As of December 31, 2000.
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
------------------------------------------------------
Depositary preferred shares, each representing Mississippi Power Company
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 Securities13
---------------------------------------------------
Company obligated mandatorily redeemable Savannah Electric and Power Company
preferred securities, $25 liquidation amount
6.85% Trust Preferred Securities14
Securities registered pursuant to Section 12(g) of the Act:15
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, $100 stated value Georgia Power Company
$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 Mississippi Power Capital Trust I and guaranteed by Mississippi
Power Company.
14 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah
Electric and Power Company.
15 As of December 31, 2000.
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, 2001: $21.1 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, 2001
The Southern Company Par Value $5 Per Share 681,946,097
Alabama Power Company Par Value $40 Per Share 5,608,955
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 2001 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
2001 Annual Meetings 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 (formerly Southern Energy, Inc.)............................ I-1
The SOUTHERN System............................................................ I-2
Integrated Southeast Utilities................................................. I-2
Other Business................................................................. I-2
Certain Factors Affecting the Industry......................................... I-3
Construction Programs.......................................................... I-3
Financing Programs............................................................. I-5
Fuel Supply.................................................................... I-6
Territory Served by the Integrated Southeast Utilities......................... I-8
Competition.................................................................... I-11
Regulation..................................................................... I-12
Rate Matters................................................................... I-14
Employee Relations............................................................. I-15
Item 2 Properties....................................................................... I-17
Item 3 Legal Proceedings................................................................ I-21
Item 4 Submission of Matters to a Vote of Security Holders.............................. I-22
Executive Officers of SOUTHERN................................................... I-23
Executive Officers of ALABAMA.................................................... I-24
Executive Officers of GEORGIA.................................................... I-25
Executive Officers of GULF....................................................... I-26
Executive Officers of MISSISSIPPI................................................ I-27
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-1
Item 12 Security Ownership of Certain Beneficial Owners and
Management.................................................................... III-1
Item 13 Certain Relationships and Related Transactions.................................. III-1
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
integrated Southeast utilities................ ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
IPP........................................... Independent power producer
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
PSC........................................... Public Service Commission
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 Nuclear.............................. Southern Nuclear Operating Company, Inc.
SOUTHERN system............................... SOUTHERN, the integrated Southeast utilities, SEGCO,
Southern Nuclear, SCS, Southern LINC, Energy Solutions and other
subsidiaries
Southern Telecom.............................. Southern Telecom, Inc.
SPC........................................... Southern Power Company
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 earnings per share and earnings growth goals. In some cases,
forward-looking statements can be identified by terminology such as "may,"
"will," "should," "expects," "plans," "anticipates," "believes," "estimates,"
"predicts," "potential" or "continue" or the negative of these terms or other
comparable terminology. The registrants caution 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 of the
integrated Southeast utilities and the race discrimination litigation against
certain of SOUTHERN's subsidiaries; the extent and timing of the entry of
additional competition in the markets of SOUTHERN's subsidiaries; potential
business strategies, including acquisitions or dispositions of assets or
businesses, which cannot be assured to be completed or beneficial; internal
restructuring or other restructuring options that may be pursued by SOUTHERN;
state and federal rate regulation in the United States and in foreign countries
in which SOUTHERN's subsidiaries operate; political, legal and economic
conditions and developments in the United States and in foreign countries in
which SOUTHERN's subsidiaries operate; financial market conditions and the
results of financing efforts; the impact of fluctuations in commodity prices,
interest rates and customer demand; weather and other natural phenomena; the
performance of projects undertaken by the non-traditional business and the
success of efforts to invest in and develop new opportunities; the timing and
acceptance of SOUTHERN's new product and service offerings; the ability of
SOUTHERN to obtain additional generating capacity at competitive prices;
developments in the California power markets, including, but not limited to,
governmental intervention, deterioration in the financial condition of
counterparties, default on receivables due, adverse results in current or future
litigation and adverse changes in the tariffs of the California Power Exchange
Corporation or the California Independent System Operator Corporation; 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 integrated
Southeast utilities supply electric service in the states of Alabama, Georgia,
Florida, Mississippi and Georgia, respectively. More particular information
relating to each of the integrated Southeast utilities 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, Energy Solutions, Southern Telecom, SPC and other direct
and indirect subsidiaries. Southern LINC provides digital wireless
communications services to SOUTHERN's integrated Southeast utilities and also
markets these services to the public within the Southeast. Southern Nuclear
provides services to ALABAMA's and GEORGIA's nuclear plants. Energy Solutions
develops new business opportunities related to energy products and services.
Southern Telecom provides wholesale fiber optic solutions to telecommunication
providers in the Southeastern United States. SPC, formed in January 2001, will
be the primary growth engine for SOUTHERN's 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 also 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
Previously, SOUTHERN owned all the outstanding common stock of Mirant. 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's common stockholders within 12 months of the initial stock offering.
On October 2, 2000, Mirant completed an initial public offering of 66.7 million
shares. On February 19, 2001, SOUTHERN's board of directors approved the spin
off of the remaining ownership of 272 million Mirant shares to be completed in a
tax free distribution on April 2, 2001. As a result of the spin off, SOUTHERN's
financial statements and related information in Item 8 herein reflect Mirant as
discontinued operations.
I-1
The SOUTHERN System
Integrated Southeast Utilities
The transmission facilities of each of the integrated Southeast utilities 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
integrated Southeast utilities 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 Integrated Southeast Utilities" 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 integrated Southeast utilities 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 integrated Southeast utilities 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 integrated Southeast utilities are represented on
the National Electric Reliability Council.
An intra-system interchange agreement provides for coordinating operations
of the power producing facilities of the integrated Southeast utilities 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 integrated Southeast utilities to provide the most economical
sources of power consistent with good operation. The resulting benefits and
savings are apportioned among the integrated Southeast utilities.
On December 20, 1999, the FERC issued its final rule on RTOs ("Order 2000").
The order encouraged utilities owning transmission systems to form RTOs on a
voluntary basis. Utilities were required to make a filing with the FERC by
October 16, 2000 explaining how they would respond to Order 2000 consistent with
this requirement. On October 16, 2000, SOUTHERN filed its RTO proposal. The
proposal is for the formation of a for-profit company that would have control of
the bulk power transmission system of SOUTHERN and other participating utilities
in the region. Participants would have the option to either maintain their
ownership, divest, sell or lease their transmission assets to the proposed RTO.
On March 14, 2001, the FERC rejected SOUTHERN's proposal on the grounds that the
limitation of the scope of services to new wholesale transmission and the
provision of incentives to passive owners were inconsistent with Order 2000.
This order requires a status report from SOUTHERN by May 14, 2001, but does not
establish a deadline for SOUTHERN to file a revised petition. Reference is made
to each registrant's "Management's Discussion and Analysis - Future Earnings
Potential" in Item 7 for additional information.
SCS has contracted with SOUTHERN, each integrated Southeast utility, Mirant,
various of the other subsidiaries, Southern Nuclear and SEGCO to furnish, at
cost and upon request, the following services: general executive and advisory
services, power pool operations, general engineering, design engineering,
purchasing, accounting, finance and treasury, taxes, insurance and pensions,
corporate, rates, budgeting, public relations, employee relations, systems and
procedures and other services with respect to business and operations. Energy
Solutions and Southern LINC have also secured from the integrated Southeast
utilities 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.
I-2
Other Business
Energy Solutions focuses on new and existing programs to enhance customer
satisfaction, efficiency and stockholder value. Examples are: Good Cents, an
energy efficiency program for electric utility customers; Energy Services, an
energy solutions consultant and contractor for industrial and large commercial
customers; and 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.
In 1996, Southern LINC began serving SOUTHERN's integrated Southeast
utilities 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 2001-2003 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 bankruptcy court that was amended on
September 15, 2000. The proposed plan of reorganization was again amended on
February 21, 2001. Reference is made to Note 3 to the financial statements of
SOUTHERN in Item 8 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."
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 2001 through
2003 by the integrated Southeast utilities, SEGCO, SCS, Southern LINC and other
subsidiaries are estimated as follows: (in millions)
------------------------------ -------- --------- ----------
2001 2002 2003
-------- --------- ----------
ALABAMA $ 735 $ 891 $ 625
GEORGIA 1,613 1,349 785
GULF 279 96 76
MISSISSIPPI 62 60 69
SAVANNAH 33 31 32
SEGCO 16 17 16
SCS 29 21 21
Southern LINC 26 39 26
Other 111 60 1
--------------------------- ----------- --------- ----------
SOUTHERN system $2,904 $2,564 $1,651
=========================== =========== ========= ==========
Included in these estimated totals are expenditures for construction of
wholesale generation assets that may be transferred to SPC. Assuming such
transfers are made, SPC's projected construction program expenditures are
approximately $1.2 billion in 2001, $725 million in 2002, and $452 million in
2003.
I-3
Estimated construction costs in 2001 are expected to be apportioned approximately as follows: (in millions)
---------------------------- ---------------- --------------- ------------- ---------- ---------------- ----------------
SOUTHERN
system* ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
---------------- --------------- ------------- ---------- ---------------- ----------------
New generation $ 940 $169 $ 596 $172 $ 3 $-
Other generating
facilities including
associated plant
substations 682 181 433 35 10 7
New business 368 129 188 22 19 10
Transmission 340 110 189 21 14 6
Joint line and substation 47 - 34 13 - -
Distribution 184 68 85 12 11 8
Nuclear fuel 93 38 55 - - -
General plant 250 40 33 4 5 2
---------------- --------------- ------------- ---------- ---------------- ----------------
$2,904 $735 $1,613 $279 $62 $33
================ =============== ============= ========== ================ ================
*Southern LINC, SCS, and other businesses plan capital additions to general
plant in 2001 of $26 million, $29 million, and $111 million, respectively, while
SEGCO plans capital additions of $16 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 6,600 megawatts of new generating capacity
scheduled to be placed in service by 2003. Approximately 4,400 megawatts of
additional new capacity will be dedicated to the wholesale market and owned by
SPC.
In 1991, the Georgia legislature passed legislation which requires GEORGIA
and SAVANNAH each 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 and GEORGIA's joint ownership of
certain generating units and related facilities with certain non-affiliated
utilities.
I-4
Financing Programs
The amount and timing of additional equity capital to be raised in 2001, as well
as 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 integrated Southeast utilities 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. Recently, the integrated Southeast utilities have 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
integrated Southeast utilities issued first mortgage bonds, mortgage backed
pollution control bonds and preferred stock to fund its external requirements.
The amount outstanding of the latter securities has been declining in recent
years.
If the integrated Southeast utilities were to choose to issue new first
mortgage bonds or preferred stock once again, they would be required to meet
certain coverage requirements.
Short-term debt is often utilized as appropriate at SOUTHERN and the
integrated Southeast utilities.
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, 2000
-------------- ---------------------
(in millions)
ALABAMA $ 750 (1) $ 281
GEORGIA 1,700 (2) 704
GULF 300(1) 43
MISSISSIPPI 350(1) 56
SAVANNAH 160(2) 75
SOUTHERN 2,000(1) 550
------------------ -------------- -- -------------------
Notes:
(1) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 2001. 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 March 31, 2008, 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 $70 million in term loans expiring January 31, 2002.
Reference is made to Note 8 to the financial statements for SOUTHERN, Note 4
to the financial statements for ALABAMA, GULF, MISSISSIPPI and SAVANNAH and Note
9 to the financial statements for GEORGIA in Item 8 herein for information
regarding the registrants' credit arrangements.
I-5
Fuel Supply
The integrated Southeast utilities' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1998 through
2000 and the estimates for 2001 are shown below:
Oil and
ALABAMA Coal Nuclear Hydro Gas
--------- ---------- --------- ---------
1998 72 18 8 2
1999 72 20 5 3
2000 72 19 3 6
2001 70 16 5 9
GEORGIA
1998 73 22 3 2
1999 75 22 1 2
2000 76 21 1 2
2001 75 21 3 1
GULF
1998 98 ** ** 2
1999 97 ** ** 3
2000 98 ** ** 2
2001 98 ** ** 2
MISSISSIPPI
1998 80 ** ** 20
1999 81 ** ** 19
2000 83 ** ** 17
2001 78 ** ** 22
SAVANNAH
1998 76 ** ** 24
1999 78 ** ** 22
2000 88 ** ** 12
2001 85 ** ** 15
SEGCO
1998 100 ** ** *
1999 100 ** ** *
2000 100 ** ** *
2001 100 ** ** *
SOUTHERN system***
1998 76 16 4 4
1999 78 17 2 3
2000 76 16 4 4
2001 76 15 3 6
---------- ------- --------- ---------- --------- ---------
*Less than 0.5%.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted averages of the integrated
Southeast utilities and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 1998
through 2000 are shown below:
1998 1999 2000
- ------------------- -------------- ------------- -------------
ALABAMA 1.54 1.44 1.54
GEORGIA 1.36 1.34 1.39
GULF 1.69 1.60 1.68
MISSISSIPPI 1.62 1.65 1.80
SAVANNAH 2.33 2.20 2.28
SEGCO 1.53 1.77 1.51
SOUTHERN
System* 1.48 1.45 1.51
- ------------------- -------------- ------------- -------------
* Amounts shown for the SOUTHERN system are weighted averages of the
integrated Southeast utilities and SEGCO.
See SELECTED FINANCIAL DATA in Item 6 herein for each registrant's source
of energy supply.
I-6
As of February 9, 2001, the integrated Southeast utilities had stockpiles of
coal on hand at their respective coal-fired plants which represented an
estimated 23 days of recoverable supply for bituminous coal and 31 days for
sub-bituminous coal. It is estimated that approximately 68 million tons of coal
will be consumed in 2001 by the integrated Southeast utilities (including those
units GEORGIA owns jointly with OPC, MEAG and Dalton and operates for FP&L and
JEA and the units ALABAMA owns jointly with AEC). The integrated Southeast
utilities currently have 60 coal contracts. These contracts cover remaining
terms of up to 12 years. Approximately 15% of 2001 estimated coal requirements
will be purchased in the spot market. Additionally, it has been determined that
approximately 34 normal full load days of recoverable supply is desirable at the
beginning of the heavy burn season between June 1 and September 30 with 31
normal full load days being the average annual target.
In 2000, the weighted average sulfur content of all coal purchased by the
integrated Southeast utilities for use in the coal-fired facilities was 0.77%
sulfur. This sulfur level, along with banked sulfur dioxide allowances, allowed
the integrated Southeast utilities and SEGCO to remain within limits as set
forth by Phase II of the Clean 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.
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. Effective
June 2000, an on-site dry storage facility for Plant Hatch became operational.
Sufficient capacity is believed to be available to continue dry storage
operations at Plant Hatch through the life of the plant. Sufficient fuel storage
capacity currently is available at Plant Vogtle to maintain full-core discharge
capability for both units into the year 2014. 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.
The Energy Act imposed upon utilities with nuclear plants, including ALABAMA
and GEORGIA, obligations for the decontamination and decommissioning of federal
nuclear fuel enrichment facilities. See Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.
I-7
Territory Served by the Integrated Southeast Utilities
The territory in which the integrated Southeast utilities 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 integrated
Southeast utilities. 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
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, the City of 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 integrated Southeast
utilities, reference is made to Item 6 herein.
A portion of the area served by the integrated Southeast utilities 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 integrated Southeast utilities 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.
I-8
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 821 megawatts and a transmission system estimated
to be 1,480 miles in length.
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. Since July 1, 1975, OPC has supplied the
requirements of the remaining 39 of these cooperative organizations from
self-owned generation acquired from GEORGIA and, until September 1991, through
partial requirements purchases from GEORGIA. GEORGIA entered into a power
coordination agreement with OPC pursuant to which, effective in September 1991,
OPC ceased to be partial requirements wholesale customer of GEORGIA. Instead,
OPC began the purchase of 1,250 megawatts of capacity from GEORGIA through 1999,
subject to reduction or extension by OPC, and may satisfy the balance of its
needs through purchases from others. OPC decreased its purchases of capacity by
250 megawatts each in September 1997, 1998 and 1999. Under the amended 1995
Integrated Resource Plan approved by the Georgia PSC in March 1997, the
resources associated with the decreased purchases by OPC in 1997, 1998 and 1999
will be used to meet the needs of GEORGIA's retail customers through 2004.
In April 1999, a new power supply agreement was implemented between GEORGIA and
OPC. Pursuant to this agreement, OPC will purchase 250 megawatts of steam
capacity through March 2006, 250 megawatts of peaking capacity through August
2000, and 125 megawatts of peaking capacity from September 2000 through August
2001.
There are 65 municipally-owned electric distribution systems operating in
the territory in which the integrated Southeast utilities 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 purchase
contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum
of 100 megawatts) for a period of 15 years commencing September 1, 1986. 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 commencing October 1, 1991. In both
contracts, the power is being sold to AMEA for its member municipalities that
previously were served directly by ALABAMA as wholesale customers. 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. 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 and purchases from
others. In August 1997, a power coordination 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 generation facilities acquired from GEORGIA and through
partial requirements purchases. 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.)
I-9
GULF and MISSISSIPPI provide wholesale requirements for one municipal
system each.
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.)
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, 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
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 information regarding
contracts for the sales and lease of capacity and energy to non-territorial
customers.
I-10
Competition
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 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 being driven down by wholesale transmission access and numerous
potential new energy suppliers, including power marketers and brokers. The
integrated Southeast utilities are aggressively working to maintain and expand
their share of wholesale sales in the Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider.
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 current energy crisis in California. As a result of
this crisis, many states have either discontinued or delayed implementation of
initiatives involving retail deregulation. The inability of a company to recover
its investments, including the regulatory assets described in Note 1 to each
registrant's respective financial statements, could have a material adverse
effect on such company's financial condition and results of operations. The
integrated Southeast utilities are attempting to minimize or reduce their cost
exposure. Reference is made to Note 3 to the financial statements for SOUTHERN
under "Alabama Power Rate Adjustment Procedures" and "Georgia Power 1998 Retail
Rate Order" for information regarding these efforts.
Reference is made to Item 1 - BUSINESS - "Integrated Southeast Utilities"
herein for information relating to an RTO filing with 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 the integrated Southeast 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, GULF, MISSISSIPPI and SAVANNAH, "Management's Discussion and Analysis -
Future Earnings Potential" in Item 7 herein for further discussion of
competition.
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 other 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
- - "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.
I-11
ALABAMA currently has cogeneration contracts in effect with twelve
industrial customers. Under the terms of these contracts, ALABAMA purchases
excess generation of such companies. During 2000, ALABAMA purchased
approximately 104.9 million kilowatt-hours from such companies at a cost of $3.1
million.
GEORGIA currently has contracts in effect with eight small power producers
whereby GEORGIA purchases their excess generation. During 2000, GEORGIA
purchased 11.6 million kilowatt-hours from such companies at a cost of $482,000.
GEORGIA has purchased power agreements for electricity with two cogeneration
facilities. Payments are subject to reductions for failure to meet minimum
capacity output. During 2000, GEORGIA purchased 698.3 million kilowatt-hours at
a cost of $70.4 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 2000, GULF purchased 127 million kilowatt-hours from such
companies for $5.2 million.
SAVANNAH currently has cogeneration contracts in effect with five large
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 2000, SAVANNAH purchased 43.9 million
kilowatt-hours from such companies at a cost of $2.7 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.
The integrated Southeast utilities 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 Integrated Southeast Utilities" herein for information
concerning suppliers of electricity operating within or near the areas served at
retail by the integrated Southeast utilities.)
Regulation
State Commissions
The integrated Southeast utilities 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 Integrated Southeast Utilities" 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 special purpose
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 integrated Southeast utilities 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.
I-12
GEORGIA has started the relicensing process for the Middle Chattahoochee
Project. 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 and Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information.)
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 2005-2036
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.
NRC operating licenses currently expire in June 2017 and March 2021 for
Plant Farley units 1 and 2, respectively, in August 2014 and June 2018 for Plant
Hatch units 1 and 2, respectively, and in January 2027 and February 2029 for
Plant Vogtle units 1 and 2, respectively. On February 29, 2000, Southern
Nuclear, on behalf of GEORGIA, filed a license renewal application with the NRC
for Plant Hatch units 1 and 2. If approved, the operating license will be
extended to 2034.
Reference is made to Notes 1 and 10 to SOUTHERN's, Notes 1 and 11 to
ALABAMA's 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 integrated Southeast utilities' 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 integrated Southeast utilities 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.
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, including a pending lawsuit brought
on behalf of the EPA.
I-13
The integrated Southeast utilities' and SEGCO's estimated capital
expenditures for environmental quality control facilities for the years 2001,
2002 and 2003 are as follows: (in millions)
--------------------- --- ---------- ---------- -----------
2001 2002 2003
---------- ---------- -----------
ALABAMA $ 76 $144 $ 48
GEORGIA 345 302 48
GULF 7 7 14
MISSISSIPPI 2 4 -
SAVANNAH 2 1 4
SEGCO 1 1 1
--------------------- --- ---------- ---------- -----------
Total $433 $459 $115
===================== === ========== ========== ===========
The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each integrated Southeast utility 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 integrated Southeast utilities 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 integrated Southeast utilities 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 integrated Southeast utilities 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 and energy adjustment 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 Note 3 to each registrant's financial statements in Item 8
herein for a discussion of rate matters. Reference is also made to GULF's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein for a discussion of recent Florida PSC matters.
I-14
Integrated Resource Planning
GEORGIA and SAVANNAH filed a new Integrated Resource Plan with the Georgia PSC
on January 31, 2001. The plans specify how GEORGIA and SAVANNAH each intends to
meet the future electrical needs of their 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
purchased power costs will be recoverable through rates.
In July 1998, the Georgia PSC approved GEORGIA's and SAVANNAH's 1998
Integrated Resource Plans as filed, with minor modifications. The approved plans
identify resource needs of approximately 800 megawatts to 1,200 megawatts
starting in the summer of 2002. As a result, GEORGIA and SAVANNAH issued a joint
request for proposals for their collective needs of 800 megawatts to 1,200
megawatts for 2002 and 2003. The bids were evaluated against self-build options,
and a certification filing for the selected resources was approved by the
Georgia PSC in March 2000. The selected resources for retail needs in Georgia
are: (1) a 7-year purchased power agreement with the West Georgia Generating
Company for 310 megawatts starting in 2002, increasing to 465 megawatts in 2005,
and terminating at the end of 2009; and (2) a 7 1/2-year purchased power
agreement for two 568 megawatt combined cycle units to be located at Plant
Wansley starting in 2002 and terminating at the end of 2009. SAVANNAH has a
7-year purchased power agreement with GEORGIA for 200 megawatts of the 1,136
megawatt addition at Plant Wansley starting in 2002 and terminating in 2009.
After 2009, this capacity will be available to the wholesale market.
On December 15, 2000, GEORGIA filed a certification request for a 7-year
purchased power agreement for 571 megawatts starting in 2003 and 610 megawatts
starting in 2004 to be served from two combined cycle units at Plant Goat Rock;
and 615 megawatts in 2004 to be served from a combined cycle unit at Plant
Autaugaville. In addition, GEORGIA is seeking certification for upgrades from 3
megawatts to 9 megawatts at Plant Goat Rock Hydro units 1 and 2.
GEORGIA expects the Georgia PSC to approve the 2001 Integrated Resource Plan
and grant certification of the purchased power agreements in July 2001.
Environmental Cost Recovery Plans
GULF and MISSISSIPPI both have retail rate mechanisms that provide for recovery
of environmental compliance costs. For a description of these plans, see Note 3
to each of GULF's and MISSISSIPPI's financial statements in Item 8 herein.
Employee Relations
The companies of the SOUTHERN system had a total of 26,021 employees on their
payrolls at December 31, 2000.
-------------------------------- --- -------------------------
Employees
at
December 31, 2000
-------------------------
ALABAMA 6,871
GEORGIA 8,855
GULF 1,327
MISSISSIPPI 1,319
SAVANNAH 554
SCS 3,431
Southern Nuclear 3,009
Other 655
-------------------------------- --- -------------------------
Total 26,021
================================ === =========================
The integrated Southeast utilities 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, 2001. 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.
I-15
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, 2001.
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 separate three-year
contracts extending to August 15, 2001 for Plant Farley and to June 30, 2002 for
Plants Hatch and Vogtle. Upon notice given at least 60 days prior to these
dates, negotiations may be initiated with respect to agreement terms to be
effective after such dates.
Southern Nuclear also has an agreement with the United Plant Guard Workers
of America for security officers at Plant Hatch extending to September 30, 2001.
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.
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-16
Item 2. PROPERTIES
Electric Properties - The Integrated Southeast Utilities
The integrated Southeast utilities and SEGCO, at December 31, 2000, operated 34
hydroelectric generating stations, 33 fossil fuel generating stations, three
nuclear generating stations and four combined cycle/cogeneration stations. The
amounts of capacity owned by 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
Dahlberg Athens, GA 640,000
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 2,535,155
---------
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-17
--------------------------- -------------------- -----------------
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
-------
241,100
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
-----------
Total Combustion Turbines 3,795,637
----------
Cogeneration
Washington County Washington
County, AL 123,428
GE Plastics Project Burkeville, AL 104,800
Theodore Theodore, AL 236,418
-----------
ALABAMA Total 464,646
-----------
Combined Cycle
Barry Mobile, AL
ALABAMA Total 535,212
-------
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 40,000
-----------
ALABAMA Total 1,593,600
----------
--------------------------- -------------------- -----------------
--------------------------- -------------------- -----------------
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 2,671,336
-----------
Total Generating Capacity 32,806,926
===========
------------------------------------------------ -----------------
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-18
Except as discussed below under "Titles to Property," the principal plants
and other important units of the integrated Southeast utilities 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, 2000, the unamortized
portion of this cost was $34.8 million.
The all-time maximum demand on the integrated Southeast utilities 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 integrated Southeast utilities 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)
Plant Miller
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-19
Titles to Property
The integrated Southeast utilities' and SEGCO's interests in the principal
plants (other than certain pollution control facilities, one small hydroelectric
generating station leased by GEORGIA 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 (except
for SEGCO) and to excepted encumbrances as defined therein. The integrated
Southeast utilities 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-20
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. ALABAMA
(United States District Court for the Northern District of Alabama)
Reference is made to Note 3 to ALABAMA's financial statements in Item 8
herein under the caption "Environmental Litigation."
(2) United States of America v. GEORGIA and SAVANNAH
(United States District Court for the Northern District of Georgia)
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 and denied
the EPA's motion to add GULF and MISSISSIPPI as defendants due to lack
of jurisdiction.
Reference is made to Note 3 to GEORGIA's financial statements in Item 8
herein under the caption "Environmental Litigation."
(3) Cooper et al. v. GEORGIA, SOUTHERN, SCS and Energy Solutions
(Superior Court of Fulton County, Georgia)
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein under the caption "Race Discrimination
Litigation."
(4) GEORGIA has been designated as a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia.
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).
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
herein under the caption "Mobile Energy Services' Petition for
Bankruptcy."
(6) Gordon v. SOUTHERN et al.
(United States District Court for the Southern District of California)
Reference is made to Note 3 to SOUTHERN"s financial statements in Item 8
herein under the caption "California Electricity Markets Litigation."
(7) Pier 23 Restaurant v. SOUTHERN et al.
(United States District Court for the Northern District of California)
Reference is made to Note 3 to SOUTHERN"s financial statements in Item 8
herein under the caption "California Electricity Markets Litigation."
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 integrated Southeast utilities, SCS, Southern
Nuclear, 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-21
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
ALABAMA
ALABAMA held a special meeting of shareholders on December 14, 2000,
for the purpose of amending its charter to provide to the holders of
Preferred Stock the right to vote at all elections of directors of
ALABAMA. The amendment was passed and the vote tabulation was as
follows:
Shares
For Against Abstain
Common Stock 5,608,955 0 0
Preferred Stock 1,505,832 462,101 127,473
--------- ------- -------
Total 7,114,787 462,101 127,473
========= ======= =======
GEORGIA
By unanimous written consent effective December 14, 2000, GEORGIA's
common shareholder authorized amending GEORGIA's charter to provide
to the holders of Preferred Stock the right to vote at all elections
of directors of GEORGIA. The vote tabulation was as follows:
Shares
For Against Abstain
Common Stock 7,761,500 0 0
GULF
GULF held a special meeting of shareholders on December 14, 2000, for
the purpose of amending its charter to provide to the holders of
Preferred Stock the right to vote at all elections of directors of
GULF. The amendment was passed and the vote tabulation was as
follows:
Shares
For Against Abstain
Common Stock 992,717 0 0
Preferred Stock 26,842 1,321 21
----------- ----- --
Total 1,019,559 1,321 21
=========== ===== ==
MISSISSIPPI
MISSISSIPPI held a special meeting of shareholders on December 14,
2000, for the purpose of amending its charter to provide to the
holders of Preferred Stock the right to vote at all elections of
directors of MISSISSIPPI. The amendment was passed and the vote
tabulation was as follows:
Shares
For Against Abstain
Common Stock 1,121,000 0 0
Preferred Stock 196,119 10,363 11,762
----------- ------ ------
Total 1,317,119 10,363 11,762
=========== ====== ======
I-22
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, 2000.
A. W. Dahlberg
Chairman and Director
Age 60
Elected Director in 1985 and Chairman effective March 1995 through March 2001,
and Chief Executive Officer effective March 1995 to March 2001. Also served as
President from January 1994 to June 1999.
H. Allen Franklin
President, Chief Executive Officer and Director
Age 56
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.
Elmer B. Harris
Executive Vice President and Director
Age 61
Elected Director in 1989 and Executive Vice President in 1991. He also has
served as President and Chief Executive Officer of ALABAMA since 1989.
David M. Ratcliffe
Executive Vice President
Age 52
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.
Stephen A. Wakefield
Senior Vice President and General Counsel
Age 60
Elected in 1997. Previously, he was a partner at the law firm of Akin, Gump,
Strauss, Hauer & Feld, LLP from July 1991 through August 1997.
Gale E. Klappa
Financial Vice President, Chief Financial Officer and Treasurer
Age 50
Elected effective March 1, 2001. Previously served as
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
Vice President
Age 49
Elected in 1998; serves as Chief Production Officer for the SOUTHERN system. He
also has served as Executive Vice President of GEORGIA since May 1998.
Previously, he served as Executive Vice President of ALABAMA from 1994 through
April 1998.
W. G. Hairston, III
Age 56
President and Chief Executive Officer of Southern Nuclear since 1993.
The officers of SOUTHERN were elected for a term running from the last
annual meeting of the directors (May 24, 2000) for one year until the next
annual meeting or until their successors are elected and have qualified, except
for Mr. Franklin and Mr. Klappa, whose elections were effective on the date
indicated.
I-23
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, 2000.
Elmer B. Harris
President, Chief Executive Officer and Director
Age 61
Elected in 1989. Served as President and Chief Executive Officer since 1989.
Elected Executive Vice President
of SOUTHERN in 1991. Served as a Director of SOUTHERN since 1989.
Michael D. Garrett
Executive Vice President
Age 51
Elected in 1998. Served as Executive Vice President of Customer Service since
January 2000. Previously served as Executive Vice President of External Affairs
from March 1998 to January 2000; and Senior Vice President of External Affairs
from February 1994 to March 1998.
William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 57
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 52
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.
Jerry L. Stewart
Senior Vice President
Age 51
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 28, 2000) for one year until the next
annual meeting or until their successors are elected and have qualified.
I-24
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, 2000.
David M. Ratcliffe
President, Chief Executive Officer and Director
Age 52
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 52
Elected in 1995. Served as Executive Vice President of External Affairs since
1995. Previously served as Senior Vice President of External Affairs from
April 1995 to September 1995.
Thomas A. Fanning
Executive Vice President, Treasurer and
Chief Financial Officer
Age 43
Elected in 1999. Previously served as Senior Vice President of SOUTHERN from
June 1998 to June 1999; and Senior Vice President and Chief Information Officer
for SOUTHERN from March 1995 to 1998.
Gene R. Hodges
Executive Vice President
Age 62
Elected in 1986. Served as Executive Vice President of Customer Operations,
Power Delivery and Safety since 1992.
James K. Davis
Senior Vice President
Age 60
Elected in 1993. Served as Senior Vice President of Corporate Relations since
1993, with Employee Relations being added to his responsibilities in 2000.
Robert H. Haubein
Senior Vice President
Age 60
Elected in 1992. Served as Senior Vice President of Fossil/Hydro Power since
1994.
Leonard J. Haynes
Senior Vice President
Age 50
Elected in 1998. Served as Senior Vice President of Marketing since 1998.
Previously served as Vice President of Retail Sales and Services from October
1995 to November 1998.
Fred D. Williams
Senior Vice President
Age 56
Elected in 1992. Served as Senior Vice President of Resource Policy and Planning
since 1998. Previously served as Senior Vice President of Wholesale Power
Marketing from 1995 to 1998.
The officers of GEORGIA were elected for a term running from the last annual
meeting of the directors (May 17, 2000) for one year until the next annual
meeting or until their successors are elected and have qualified.
I-25
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, 2000.
Travis J. Bowden
President, Chief Executive Officer and Director
Age 62
Elected in 1994. Served as President and Chief Executive Officer since 1994.
Francis M. Fisher, Jr.
Vice President
Age 52
Elected in 1989. Served as Vice President of Power Delivery and Customer
Operations since 1996. Previously served as Vice President of Employee and
External Relations from 1989 to 1996.
John E. Hodges, Jr.
Vice President
Age 57
Elected in 1989. Served as Vice President of Marketing and Employee/External
Affairs since 1996. Previously served as Vice President of Customer Operations
from 1989 to 1996.
Ronnie R. Labrato
Comptroller and Chief Financial Officer
Age 47
Elected as an Executive Officer in July 2000. Previously served as Controller
from 1992 to 2000.
Robert G. Moore
Vice President
Age 51
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
Secretary/Treasurer and
Regional Chief Information Officer
Age 58
Elected as an Executive Officer in July 2000. Served 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 28, 2000) for one year until the next annual
meeting or until their successors are elected and have qualified.
I-26
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, 2000.
Dwight H. Evans
President, Chief Executive Officer and Director
Age 52
Elected in 1995. Previously served as Executive Vice President of External
Affairs of GEORGIA from 1989 to 1995.
H. E. Blakeslee
Vice President
Age 60
Elected in 1984. Served as Vice President of Customer Services and Retail
Marketing since 1984.
Don E. Mason
Vice President
Age 59
Elected in 1983. Served as Vice President of External Affairs and Corporate
Services since 1983.
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
Age 48
Elected in 1995. Served as Vice President, Secretary, Treasurer and Chief
Financial Officer since 1995.
Gene L. Ussery, Jr.
Vice President
Age 51
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 26, 2000) for one year until the next
annual meeting or until their successors are elected and have qualified, except
for Mr. Ussery, whose election was effective on September 21, 2000.
I-27
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
----------- --------------
2000
First Quarter $25-7/8 $20-3/8
Second Quarter 27-7/8 21-11/16
Third Quarter 35 23-13/32
Fourth Quarter 33-22/25 27-1/2
1999
First Quarter $29-5/8 $23-1/4
Second Quarter 29-3/16 22-3/4
Third Quarter 28 25
Fourth Quarter 27-1/8 22-1/16
-------------------- --------------- --- --------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 28, 2001, the closing price
of SOUTHERN's common stock was $30.95.
(b) Number of SOUTHERN's common stockholders at December 31, 2000:
160,116
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 integrated Southeast
utilities to their stockholder(s) for the past two years were as
follows: (in thousands)
------------------- --------- ------------- ----------
Registrant Quarter 2000 1999
------------------- --------- ------------- ----------
SOUTHERN First $220,557 $233,879
Second 217,289 233,445
Third 217,289 228,690
Fourth 218,098 225,470
ALABAMA First 103,600 98,000
Second 105,200 98,400
Third 104,400 99,700
Fourth 103,900 103,500
GEORGIA First 136,500 133,100
Second 138,600 133,700
Third 137,600 135,500
Fourth 136,900 140,700
GULF First 14,600 15,000
Second 14,900 15,100
Third 14,800 15,300
Fourth 14,700 15,900
MISSISSIPPI First 13,600 13,800
Second 13,800 13,800
Third 13,700 14,000
Fourth 13,600 14,500
SAVANNAH First 6,100 6,200
Second 6,200 6,200
Third 6,000 6,300
Fourth 6,000 6,500
------------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of
1999 and 2000. The dividend paid on SOUTHERN's common stock for the first
quarter of 2001 was 33.5(cent) per share.
The amount of dividends on their common stock that may be paid by the
subsidiary registrants is restricted in accordance with their first mortgage
bond indenture. The amounts of earnings retained in the business
II-1
and the amounts restricted against the payment of cash dividends on common
stock at December 31, 2000 were as follows:
-------------------- ------------------ --- --------------
Retained Restricted
Earnings Amount
------------------ --------------
(in millions)
ALABAMA $1,228 $ 796
GEORGIA 1,788 891
GULF 156 127
MISSISSIPPI 173 118
SAVANNAH 110 68
Consolidated 4,672 2,000
-------------------- ------------------ --- --------------
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-41 and
II-42.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-74 and II-75.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-109 and II-110.
GULF. Reference is made to information under the heading "Selected Financial
and Operating Data," contained herein at pages II-138 and II-139.
MISSISSIPPI. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-167 and II-168.
SAVANNAH. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-194 and II-195.
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-17.
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-46 through II-54.
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-79 through II-87.
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-114 through II-122.
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-143 through II-150.
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-172 through II-178.
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 for Non-Trading Activities" contained
herein on pages II-13 through II-14 and II-28, 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-51, II-83. II-118, II-146, and II-175,
respectively.
II-2
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2000 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, 2000, 1999 and 1998.................. II-18
Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998.............. II-19
Consolidated Balance Sheets at December 31, 2000 and 1999............................................... II-20
Consolidated Statements of Capitalization at December 31, 2000 and 1999................................. II-22
Consolidated Statements of Common Stockholders' Equity for the Years Ended
..... December 31, 2000, 1999 and 1998................................................................ II-24
Consolidated Statements of Comprehensive Income for the Years Ended
..... December 31, 2000, 1999 and 1998................................................................ II-24
Notes to Financial Statements........................................................................... II-25
ALABAMA:
Report of Independent Public Accountants .............................................................. II-45
Statements of Income for the Years Ended December 31, 2000, 1999 and 1998............................... II-55
Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998........................... II-56
Balance Sheets at December 31, 2000 and 1999 ........................................................... II-57
Statements of Capitalization at December 31, 2000 and 1999 ............................................. II-59
Statements of Common Stockholder's Equity for the Years Ended
..... December 31, 2000, 1999 and 1998............................................................... II-61
Notes to Financial Statements........................................................................... II-62
GEORGIA:
Report of Independent Public Accountants................................................................ II-78
Statements of Income for the Years Ended December 31, 2000, 1999 and 1998............................... II-88
Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998........................... II-89
Balance Sheets at December 31, 2000 and 1999 ........................................................... II-90
Statements of Capitalization at December 31, 2000 and 1999 ............................................. II-92
Statements of Common Stockholder's Equity for the Years Ended
..... December 31, 2000, 1999 and 1998............................................................... II-94
Notes to Financial Statements........................................................................... II-95
GULF:
Report of Independent Public Accountants................................................................ II-113
Statements of Income for the Years Ended December 31, 2000, 1999 and 1998............................... II-123
Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998........................... II-124
Balance Sheets at December 31, 2000 and 1999 ........................................................... II-125
Statements of Capitalization at December 31, 2000 and 1999 ............................................. II-127
Statements of Common Stockholder's Equity for the Years Ended
..... December 31, 2000, 1999 and 1998............................................................... II-128
Notes to Financial Statements........................................................................... II-129
II-3
Page
MISSISSIPPI:
Report of Independent Public Accountants................................................................ II-142
Statements of Income for the Years Ended December 31, 2000, 1999 and 1998............................... II-151
Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998........................... II-152
Balance Sheets at December 31, 2000 and 1999 ........................................................... II-153
Statements of Capitalization at December 31, 2000 and 1999 ............................................. II-155
Statements of Common Stockholder's Equity for the Years Ended
..... December 31, 2000, 1999 and 1998............................................................... II-157
Notes to Financial Statements........................................................................... II-158
SAVANNAH:
Report of Independent Public Accountants................................................................ II-171
Statements of Income for the Years Ended December 31, 2000, 1999 and 1998............................... II-179
Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998........................... II-180
Balance Sheets at December 31, 2000 and 1999 ........................................................... II-181
Statements of Capitalization at December 31, 2000 and 1999 ............................................. II-183
Statements of Common Stockholder's Equity for the Years Ended
..... December 31, 2000, 1999 and 1998............................................................... II-184
Notes to Financial Statements........................................................................... II-185
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
II-4
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 2000 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 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 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
President and Chief Executive Officer
/s/Gale E. Klappa
Gale E. Klappa
Financial Vice President, Chief Financial Officer,
and Treasurer
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, 2000 and 1999, 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, 2000. 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-18 through
II-40)referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 2000
and 1999, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2000, in conformity with
accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 28, 2001
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 2000 Annual Report
RESULTS OF OPERATIONS
- ---------------------
OVERVIEW OF CONSOLIDATED EARNINGS
Southern Company's solid financial performance resulted in record earnings for
2000. Higher earnings were driven by both strong growth of selling electricity
in the Southeast and by the global subsidiary's competitive energy supply
business outside the Southeast. Reported earnings in both 2000 and 1999
reflected significant items not related to the normal day-to-day business
activities. After adjusting for these items, earnings per share for 2000 was
$2.13 compared with $1.90 in 1999. Earnings as reported and the details of
earnings as adjusted are shown in the following table.
In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant Corporation -- formerly Southern Energy, Inc. -- 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 an initial public offering of 66.7 million shares of common
stock.
On February 19, 2001, Southern Company's board of directors approved the spin
off of the remaining ownership of 272 million Mirant shares to be completed in a
tax free distribution on April 2, 2001. As a result of the spin off, Southern
Company financial statements and related information reflect Mirant as
discontinued operations.
A reconciliation of reported consolidated earnings, including discontinued
operations, to earnings as adjusted -- which exclude non-day to day business
items -- and the related explanations are as follows:
Consolidated Earnings
Net Income Per Share
---------------- --------------
2000 1999 2000 1999
--------------- ---------------
(in millions)
Earnings from --
Continuing
operations $ 994 $ 915 $1.52 $1.33
Discontinued
operations 319 361 .49 .53
- ---------------------------------------------------------------
Earnings as reported 1,313 1,276 2.01 1.86
- ---------------------------------------------------------------
Mirant transition costs 80 - .12 -
Mobile Energy
write down 10 69 .01 .10
Gain on asset sale - (78) - (.11)
Work force reductions - 50 - .07
Other (8) (14) (.01) (.02)
- ---------------------------------------------------------------
Total adjustments 82 27 .12 .04
- ---------------------------------------------------------------
Earnings as adjusted $1,395 $1,303 $2.13 $1.90
===============================================================
Mirant's transition costs shown in the table include charges related to
becoming a public company and changes in their tax strategy in Asia.
In 2000 and 1999, Southern Company recorded asset impairment charges related
to Mobile Energy Services -- see Note 3 to the financial statements. In 1999,
Mirant sold a portion of its business in the United Kingdom. Work force
reduction programs began in late 1999 for a German utility in which Mirant has
an ownership interest.
SOUTHERN COMPANY BUSINESS ACTIVITIES
Discussion of the results of operations is focused on the traditional business
of the integrated Southeast utilities. The remaining portion of Southern
Company's other business activities include telecommunications, energy products
and services, leveraged leasing activities, as well as the parent holding
company. The impact of these other business activities on the consolidated
results of operations is not significant. For more information, see Note 12.
Integrated Southeast Utilities
The five integrated Southeast utilities provide electric service in four states.
These utilities are Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
and Savannah Electric. A condensed income statement for these companies is as
follows:
Increase (Decrease)
Amount From Prior Year
------ --------------------
2000 2000 1999
--------------------------------------------------------------
(in millions)
Operating revenues $9,860 $735 $(238)
- ---------------------------------------------------------------
Fuel 2,564 236 7
Purchased power 677 268 13
Other operation
and maintenance 2,472 41 4
Depreciation
and amortization 1,135 89 (277)
Taxes other than
income taxes 532 11 13
- ---------------------------------------------------------------
Total operating expenses 7,380 645 (240)
- ---------------------------------------------------------------
Operating income 2,480 90 2
Other income, net (18) (11) (84)
- ---------------------------------------------------------------
Earnings before
interest and taxes 2,462 79 (82)
Interest expenses
and other 650 15 (44)
Income taxes 703 28 (28)
- ---------------------------------------------------------------
Net income $1,109 $ 36 $ (10)
===============================================================
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
Revenues
Operating revenues for the integrated Southeast utilities in 2000 and the amount
of change from the prior year are as follows:
Increase (Decrease)
Amount From Prior Year
------- --------------------
2000 2000 1999
- ---------------------------------------------------------------
(in millions)
Retail --
Base revenues $6,014 $174 $(262)
Fuel cost recovery
and other 2,599 353 76
- ---------------------------------------------------------------
Total retail 8,613 527 (186)
- ---------------------------------------------------------------
Sales for resale --
Within service area 377 27 (24)
Outside service area 600 127 (49)
- ----------------------------------------------------------------
Total sales for resale 977 154 (73)
Other operating
revenues 270 54 21
- ---------------------------------------------------------------
Operating revenues $9,860 $735 $(238)
===============================================================
Percent change 8.1% (2.5)%
- ---------------------------------------------------------------
Base revenues increased $174 million in 2000 as a result of continued
customer growth in the traditional service area and the positive impact of
weather on energy sales. However, total base revenues of $5.8 billion in 1999
declined as a result of a Georgia Power rate reduction and recorded revenue
sharing in 1999. For additional information, see Note 3 to the financial
statements under "Georgia Power 1998 Retail Rate Order." Customer growth in the
Southeast somewhat offset the rate decrease.
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 economic loss from
untimely recovery of these receivables. Each company has filed or will be filing
for approval of new fuel rates to be more reflective of escalating fuel costs.
Revenues from sales for resale within the service area were up as a result of
additional demand during the hot summer of 2000. Sales for resale revenues
within the service area were $350 million in 1999, down 6.5 percent from the
prior year. This sharp decline resulted primarily from supplying less
electricity under contractual agreements with certain wholesale customers in
1999.
Energy sales for resale outside the service area are principally unit power
sales under long-term contracts to Florida utilities. Economy energy and energy
under short-term contracts are also sold for resale outside the service area.
Revenues from long-term unit 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. The
capacity and energy components of the unit power contracts were as follows:
2000 1999 1998
- ---------------------------------------------------------------
(in millions)
Capacity $177 $174 $196
Energy 178 157 152
- ---------------------------------------------------------------
Total $355 $331 $348
===============================================================
Capacity revenues in 2000 and 1999 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
The changes in revenues for the traditional business in the Southeast are
influenced heavily by the amount of energy sold each year. Kilowatt-hour sales
for 2000 and the percent change by year were as follows:
Amount Percent Change
(billions of ------ ---------------------------
kilowatt-hours) 2000 2000 1999 1998
- ---------------------------------------------------------------
Residential 46.2 6.5% (0.2)% 10.9%
Commercial 46.2 6.6 4.0 7.2
Industrial 56.7 1.0 1.6 2.1
Other 1.0 2.7 1.6 3.1
-----
Total retail 150.1 4.3 1.7 6.2
Sales for resale --
Within service area 9.6 1.5 (4.1) (0.4)
Outside service area 17.2 33.0 (0.4) (5.6)
-----
Total 176.9 6.4 1.2 4.7
===============================================================
The rate of growth in 2000 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 number of residential customers served
increased by 59,000 during the year. Commercial and industrial sales, both in
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
2000 and 1999, continued to show slight gains in excess of the national
averages. This reflects the strength of business and economic conditions in
Southern Company's traditional service area in the southeastern United States.
The rate of increase in 1999 total retail energy sales was significantly lower
than in 1998. Residential energy sales experienced a decline as a result of
milder weather in 1999, which strongly affected the total retail sales increase
of 1.7 percent. Energy sales to retail customers are projected to increase at an
average annual rate of 2.1 percent during the period 2001 through 2011.
Sales to customers outside the service area under long-term contracts for
unit power sales increased 21 percent in 2000 and increased 19 percent in 1999.
These changes in sales were influenced by weather and fluctuations in prices for
oil and natural gas, 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 2000, operating expenses of $7.4 billion increased $645 million compared with
the prior year. The costs to produce electricity for the traditional business in
2000 increased by $498 million to meet higher energy demands. Non-production
operation and maintenance expenses increased $47 million in 2000. In 2000,
depreciation and amortization expenses increased $89 million of which $50
million resulted from the 1998 Georgia Power rate order as referred to earlier.
In 1999, operating expenses of $6.7 billion decreased $240 million. This
decline was driven by a reduction of $277 million accelerated depreciation of
plant being recorded primarily as a result of the 1998 Georgia Power rate order.
The costs to produce electricity for the traditional business in the Southeast
for 1999 increased by $68 million to meet higher energy demands. All other
operation and maintenance expenses declined by $44 million.
Fuel costs constitute the single largest expense for the integrated Southeast
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
traditional business service area -- were as follows:
2000 1999 1998
- -------------------------------------------------------------------
Total generation
(billions of kilowatt-hours) 174 165 164
Sources of generation
(percent) --
Coal 78 78 77
Nuclear 16 17 16
Hydro 2 2 4
Oil and gas 4 3 3
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.51 1.45 1.48
- -------------------------------------------------------------------
In 2000, fuel and purchased power costs increased $504 million 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 last year.
Total fuel and purchased power costs of $2.7 billion in 1999 increased only
$20 million while total energy sales increased 2.0 billion kilowatt-hours
compared with the amounts recorded in 1998. Continued efforts to control energy
costs helped lower the average cost of fuel per net kilowatt-hour generated in
1999.
Total interest charges and other financing costs in 2000 increased $15
million reflecting new generating units being constructed requiring some
external financing. Total interest charges and other financing costs in 1999
decreased $44 million from amounts reported in the previous year. The decline
reflected additional refinancing of debt in 1999.
Discontinued Operations
Mirant is a global energy company whose businesses include competitive
electricity distribution companies, independent power projects, and energy
trading and risk management companies.
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
On February 19, 2001, Southern Company's board of directors approved the spin
off of Mirant, to be effective on April 2, 2001. As a result of this action,
Mirant's financial and related information is shown as discontinued operations.
All historical financial statements, footnotes, and related disclosures have
been reclassified to conform with the current year presentation.
Earnings from discontinued operations are shown net of income taxes and
minority interest. Southern Company earnings per share as adjusted was $2.13 in
2000, of which Mirant's earnings as adjusted contributed approximately $0.60 per
share. On the same basis in 1999, Southern Company earnings per share was $1.90,
of which $0.47 was attributed to Mirant.
Effects of Inflation
Southern Company's traditional business of the integrated Southeast utilities 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 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 financing facilities with
fixed-money obligations such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
The results of 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 regulated integrated Southeast utilities 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.
The traditional business or the five Southeast utilities currently operate as
vertically integrated companies providing electricity to customers within the
traditional 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.
Future earnings for the traditional 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 traditional service
area.
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
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 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 current energy crisis in California. As a result of this crisis, many states
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
have either discontinued or delayed implementation of initiatives involving
retail deregulation. The inability of a company to recover its investments,
including the regulatory assets described in Note 1 to the financial statements,
could have a material adverse effect on 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 Southern Company's integrated Southeast 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 other 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.
On December 20, 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. After participating in regional conferences with customers and other
members of the public to discuss the formation of RTOs, utilities were required
to make a filing with the FERC. Southern Company filed on October 16, 2000, a
proposal for the creation of an RTO. The proposal is for the formation of a
for-profit company that would have control of the bulk power transmission system
of Southern Company and any other participating utilities. Participants would
have the option to either maintain their ownership, divest, sell, or lease their
assets to the proposed RTO. If the FERC accepts the proposal as filed, the
creation of an RTO is not expected to have a material impact on Southern
Company's financial statements. The outcome of this matter cannot now be
determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to allow holding companies to form exempt wholesale generators to sell power
largely free of 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 aggressively working to maintain and expand its share of
wholesale sales in the southeastern power markets. In January 2001, Southern
Company announced the formation of a new subsidiary -- Southern Power Company.
The new subsidiary will own, manage, and finance wholesale generating assets in
the Southeast. Southern Power will be the primary growth engine for Southern
Company's market-based energy business. Energy from its assets will be marketed
to wholesale customers under the Southern Company name. By 2005, plans call for
Southern Power to have developed or acquired more than 7,500 megawatts dedicated
to the competitive wholesale business. Within 10 years, the new wholesale
generating company's goal is to own more than 15,000 megawatts.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, Southern Company recorded non-cash
income of approximately $130 million in 2000. Pension plan income in 2001 is
expected to be less as a result of plan amendments. Future pension income is
dependent on several factors including trust earnings and changes to the plan.
For more information, see Note 2.
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."
The staff of the SEC has questioned certain of the current accounting
practices of the electric utility industry -- including Southern Company's --
regarding the recognition, measurement, and classification in the financial
statements of decommissioning costs for nuclear generating facilities. In
response to these questions, the Financial Accounting Standards Board (FASB) is
reviewing the accounting for liabilities related to the retirement of long-lived
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
assets, including nuclear decommissioning. If the FASB issues new accounting
rules, the estimated costs of retiring Southern Company's nuclear and other
facilities may be required to be recorded as liabilities in the Consolidated
Balance Sheets. Also, the annual provisions for such costs could change. Because
of the company's current ability to recover asset retirement costs through
rates, these changes would not have a significant adverse effect on results of
operations. See Note 1 to the financial statements under "Depreciation and
Nuclear Decommissioning" for additional information.
The integrated Southeast utilities 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 Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities. Statement No.
133, as amended, establishes accounting and reporting standards for derivative
instruments and for hedging activities. Statement No. 133 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.
Southern Company utilizes financial instruments to reduce its exposure to
changes in interest rates and foreign currency exchange rates. Southern Company
also enters into commodity related forward contracts to limit exposure to
changing prices on certain fuel purchases and electricity purchases and sales.
Substantially all of these bulk energy purchases and sales meet the
definition of a derivative under Statement No. 133. In many cases, these
transactions meet the normal purchase and sale exception and the related
contracts will continue to be accounted for under the accrual method. Certain of
these instruments qualify as cash flow hedges resulting in the deferral of
related gains and losses in other comprehensive income until the hedged
transactions occur. Any ineffectiveness will be recognized currently in net
income. However, others will be required to be marked to market through current
period income.
Southern Company adopted Statement No. 133 effective January 1, 2001. The
cumulative effect of adoption was a reduction of approximately $300 million in
comprehensive income, which was all related to discontinued operations. The
impact on net income was immaterial. The application of the new rules is still
evolving and further guidance from FASB is expected, which could additionally
impact Southern Company's financial statements. Also, as wholesale energy
markets mature, the accounting for future transactions could be significantly
impacted by Statement No. 133, resulting in more volatility in net income and
comprehensive income.
FINANCIAL CONDITION
- ------------------
Overview
Southern Company's financial condition continues to remain strong. In 2000, the
integrated Southeast utilities' earnings were at the high end of their
respective allowed range of return on equity. Also, earnings from discontinued
operations made a solid contribution. These factors drove the reported
consolidated net income to a record $1.31 billion in 2000. The quarterly
dividend declared in January 2001 was 33 1/2 cents per share, or $1.34 annually.
Southern Company is committed to a goal of maintaining its current annual
dividend of $1.34 per share and to grow the dividend over time consistent with
earnings expectations. After the Mirant spin off, Southern Company's target
will be to grow earnings per share at an average annual rate of 3 to 5 percent.
Gross property additions to utility plant from continuing operations were
$2.2 billion in 2000. The majority of funds needed for gross property additions
since 1997 has been provided from operating activities. The Consolidated
Statements of Cash Flows provide additional details.
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
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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. Generally, company
policy is that derivatives are to be used only 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 versus the previous reporting period. In addition, the
company is not aware of any facts or circumstances that would significantly
impact such exposures in the near-term.
If the company sustained a 100 basis point change in interest rates for all
variable rate debt, the change would affect annualized interest expense by
approximately $23 million at December 31, 2000. Based on the company's overall
interest rate exposure at December 31, 2000, 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 integrated Southeast utilities 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, the companies enter 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, 2000, exposure from these activities was not material to the
consolidated financial statements.
For additional information, see Note 1 to the financial statements under
"Financial Instruments for Non-Trading Activities."
Capital Structure
During 2000, the integrated Southeast utilities sold, through public
authorities, $79 million of pollution control revenue bonds. In addition, senior
notes of $650 million were issued in 2000. The companies continued to reduce
financing costs by retiring higher-cost securities. Retirements of bonds and
senior notes, including maturities, totaled $298 million during 2000, $1.2
billion during 1999, and $1.7 billion during 1998. Retirements of preferred
stock totaled $86 million during 1999 and $239 million during 1998.
In December 2000, Southern Company issued 28 million treasury shares of
common stock through a public offering. The offering raised $800 million and
was priced at $28.50 per share. The proceeds were used to reduce debt.
In April 1999, Southern Company announced the repurchase of up to 50 million
shares of its 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. Funding for the
program was provided from Southern Company's commercial paper program. At the
close of 2000, the company's common stock market value was 33 1/4 per share,
compared with book value of $15.69 per share. The market-to-book value ratio was
212 percent at the end of 2000, compared with 170 percent at year-end 1999, and
207 percent at year-end 1998.
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $2.9 billion for
2001, $2.6 billion for 2002, and $1.7 billion for 2003. 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 6,300 megawatts of new generating capacity
scheduled to be placed in service by 2003. Approximately 4,100 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 for the
traditional business in the Southeast.
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $1.4
billion will be required by the end of 2003 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.
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 the integrated Southeast
utilities 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 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 the system
service company's motion to dismiss on the grounds that it neither owned nor
operated the generating units involved in the proceedings. On January 12, 2001,
the EPA re-filed its claims against Alabama Power in federal district court in
Birmingham, Alabama. The EPA did not include the system service company in the
new complaint. Southern Company believes that its integrated utilities 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 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
and some 50 generating units were brought into compliance with Phase I
requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I 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.
The one-hour ozone non-attainment standards for the Atlanta and Birmingham
areas have been set and must be implemented in May 2003. Seven generating plants
will be affected in the Atlanta area and two plants in the Birmingham area.
Additional construction expenditures for compliance with these new rules are
currently estimated at approximately $935 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.
II-15
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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 recently dismissed certain challenges but 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
will address other legal challenges to these standards in mid-2001. If the
standards are eventually upheld, implementation could be required by 2007 to
2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction
rules to the states for implementation. Compliance is required by May 31, 2004.
The final rule affects 21 states, including Alabama and Georgia. Additional
construction expenditures for compliance with these new rules are currently
estimated at approximately $195 million.
In December 2000, the EPA completed its utility studies 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 (MACT) provisions of the Clean Air Act. This determination is being
challenged in the courts. 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 BART rules is probable in the near
future.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C.
add to the uncertainties associated with BART guidance and the MACT
determination for mercury and other HAPS.
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; 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 costs and have recognized in their respective financial
statements costs to clean up known sites. These costs for Southern Company
amounted to $4 million in 2000, $4 million in 1999, and $6 million in 1998.
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 a site in Brunswick, Georgia.
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 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
II-16
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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 2001 -- 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 integrated Southeast utilities 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 2001 approximately $199 million of cash and cash equivalents and
$5.1 billion of unused credit arrangements with banks.
Cautionary Statement Regarding
Forward-Looking Information
Southern Company's 2000 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 earnings per share and
earnings growth goals. In some cases, forward-looking statements can be
identified by terminology such as "may," "will," "should," "expects," "plans,"
"anticipates," "believes," "estimates," "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 Georgia Power and potentially other of Southern
Company's subsidiaries and the race discrimination litigation against certain of
Southern Company's subsidiaries; the extent and timing of the entry of
additional competition in the markets of Southern Company's subsidiaries;
potential business strategies, including acquisitions or dispositions of assets
or businesses, which cannot be assured to be completed or beneficial; internal
restructuring or other restructuring options, that may be pursued by Southern
Company; state and federal rate regulation in the United States and in foreign
countries in which Southern Company's subsidiaries operate; political, legal and
economic conditions and developments in the United States and in foreign
countries in which Southern Company's subsidiaries operate; financial market
conditions and the results of financing efforts; the impact of fluctuations in
commodity prices, interest rates and customer demand; weather and other natural
phenomena; the performance of projects undertaken by the non-traditional
business and the success of efforts to invest in and develop new opportunities;
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; developments in the California power markets,
including, but not limited to, governmental intervention, deterioration in the
financial condition of counterparties, default on receivables due, adverse
results in current or future litigation and adverse changes in the tariffs of
the California Power Exchange Corporation or the California Independent System
Operator Corporation; and other factors discussed elsewhere herein and in other
reports (including Form 10-K) filed from time to time by Southern Company with
the SEC.
II-17
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Southern Company and Subsidiary Companies 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Revenues:
Retail sales $ 8,613 $8,086 $8,272
Sales for resale 977 823 896
Other revenues 476 408 331
- ----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 10,066 9,317 9,499
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 2,564 2,328 2,321
Purchased power 677 409 396
Other operations 1,862 1,839 1,852
Maintenance 852 829 800
Depreciation and amortization 1,171 1,139 1,340
Taxes other than income taxes 536 523 511
- ----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 7,662 7,067 7,220
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income 2,404 2,250 2,279
Other Income:
Interest income 51 70 154
Other, net (26) (55) (53)
- ----------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations
Before Interest and Income Taxes 2,429 2,265 2,380
- ----------------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 659 556 558
Distributions on capital and preferred securities of subsidiaries 169 175 141
Preferred dividends of subsidiaries 19 20 25
- ----------------------------------------------------------------------------------------------------------------------------
Total interest and other 847 751 724
- ----------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before Income Taxes 1,582 1,514 1,656
Income taxes 588 599 670
- ----------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations 994 915 986
Earnings from discontinued operations,
net of income taxes of $86, $127,
and $(121) for 2000, 1999, and 1998, respectively 319 361 (9)
- ----------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 1,313 $1,276 $ 977
============================================================================================================================
Common Stock Data:6
Basic and diluted earnings per share of common stock -
Earnings per share from continuing operations $1.52 $1.33 $ 1.41
Earnings per share from discontinued operations (Note 11) 0.49 0.53 (0.01)
- ----------------------------------------------------------------------------------------------------------------------------
Consolidated Basic and Diluted Earnings Per Share $2.01 $1.86 $1.40
============================================================================================================================
Average number of shares of common stock outstanding (in millions) 653 685 697
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-18
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
Southern Company and Subsidiary Companies 2000 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Activities:
Consolidated net income $ 1,313 $ 1,276 $ 977
Adjustments to reconcile consolidated net income
to net cash provided from operating activities --
Less income from discontinued operations (Note 11) 319 361 (9)
Depreciation and amortization 1,337 1,216 1,530
Deferred income taxes and investment tax credits 97 10 21
Gain on asset sales 5 (2) (20)
Other, net 455 888 (40)
Changes in certain current assets and liabilities --
Receivables, net (379) (141) (49)
Fossil fuel stock 78 (41) (24)
Materials and supplies (15) (37) 10
Accounts payable 180 (65) 103
Other 66 244 (200)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities of continuing operations 2,818 2,987 2,317
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (2,225) (1,881) (1,356)
Sales of property - - 83
Other (81) (400) (166)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities of continuing operations (2,306) (2,281) (1,439)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (275) 831 (365)
Proceeds --
Other long-term debt 743 1,469 2,496
Capital and preferred securities - 250 435
Preferred stock - - 200
Common stock 910 24 234
Redemptions --
First mortgage bonds (211) (890) (1,479)
Other long-term debt (204) (483) (278)
Capital and preferred securities - (100) -
Preferred stock - (86) (239)
Common stock repurchased (415) (862) (125)
Payment of common stock dividends (873) (921) (933)
Other (54) (76) (155)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for)
financing activities of continuing operations (379) (844) (209)
- -------------------------------------------------------------------------------------------------------------------------------
Cash used for discontinued operations (88) (20) (534)
- -------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 45 (158) 135
Cash and Cash Equivalents at Beginning of Year 154 312 177
- -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 199 $ 154 $ 312
===============================================================================================================================
Supplemental Cash Flow Information
From Continuing Operations:
Cash paid during the year for --
Interest (net of amount capitalized) $802 $684 $680
Income taxes $661 $656 $757
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-19
CONSOLIDATED BALANCE SHEETS
At December 31, 2000 and 1999
Southern Company and Subsidiary Companies 2000 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
Assets 2000 1999
- -------------------------------------------------------------------------------------------------------------------------
(in millions)
Current Assets:
Cash and cash equivalents $ 199 $ 154
Special deposits 6 22
Receivables, less accumulated provisions for uncollectible accounts
of $22 in 2000 and $22 in 1999 1,312 1,043
Unrecovered retail fuel clause revenue 418 244
Fossil fuel stock, at average cost 195 274
Materials and supplies, at average cost 508 493
Other 187 132
- -------------------------------------------------------------------------------------------------------------------------
Total current assets 2,825 2,362
- -------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 34,188 32,702
Less accumulated depreciation 14,350 13,655
- -------------------------------------------------------------------------------------------------------------------------
19,838 19,047
Nuclear fuel, at amortized cost 215 227
Construction work in progress 1,569 1,265
- -------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 21,622 20,539
- -------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Nuclear decommissioning trusts, at fair value 690 658
Net assets of discontinued operations (Note 11) 3,320 2,913
Leveraged leases 596 556
Other 165 156
- -------------------------------------------------------------------------------------------------------------------------
Total other property and investments 4,771 4,283
- -------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 957 987
Prepaid pension costs 498 368
Debt expense, being amortized 99 104
Premium on reacquired debt, being amortized 280 302
Other 310 346
- -------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 2,144 2,107
- -------------------------------------------------------------------------------------------------------------------------
Total Assets $31,362 $29,291
=========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-20
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 2000 and 1999
Southern Company and Subsidiary Companies 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
(in millions)
Current Liabilities:
Securities due within one year $ 67 $ 329
Notes payable 1,680 1,955
Accounts payable 869 669
Customer deposits 140 128
Taxes accrued --
Income taxes 88 107
Other 208 198
Interest accrued 121 139
Vacation pay accrued 119 113
Other 445 391
- ----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 3,737 4,029
- ----------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 7,843 7,251
- ----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,074 3,884
Deferred credits related to income taxes 551 640
Accumulated deferred investment tax credits 664 693
Employee benefits provisions 478 465
Prepaid capacity revenues 58 80
Other 653 430
- ----------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 6,478 6,192
- ----------------------------------------------------------------------------------------------------------------------------
Company or subsidiary obligated mandatorily redeemable
capital and preferred securities (See accompanying statements) 2,246 2,246
- ----------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock of subsidiaries (See accompanying statements) 368 369
- ----------------------------------------------------------------------------------------------------------------------------
Common stockholders' equity (See accompanying statements) 10,690 9,204
- ----------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $31,362 $29,291
============================================================================================================================
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-21
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2000 and 1999
Southern Company and Subsidiary Companies 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
2000 6.00% $ - $ 200
2003 6.13% to 6.63% 325 325
2004 6.60% 35 35
2005 6.07% 10 10
2006 through 2010 6.50% to 6.90% 95 95
2021 through 2025 6.88% to 9.00% 635 646
2026 through 2030 6.88% 30 30
- ----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,130 1,341
- ----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
5.35% to 9.75% due 2001-2004 766 584
5.38% to 8.58% due 2005-2008 744 964
6.25% to 7.63% due 2009-2017 170 170
6.38% to 8.12% due 2018-2038 793 801
6.63% to 7.13% due 2039-2048 1,029 1,029
Adjustable rates (5.79% to 7.75% at 1/1/01)
due 2000-2005 734 148
- ----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 4,236 3,696
- ----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
4.38% to 6.75% due 2000-2026 539 617
Variable rates (4.73% to 5.05% at 1/1/01)
due 2015-2025 90 120
Non-collateralized:
4.53% to 6.75% due 2015-2034 406 263
Variable rates (3.50% to 5.35% at 1/1/01)
due 2011-2037 1,475 1,510
- ----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 2,510 2,510
- ----------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 95 97
- ----------------------------------------------------------------------------------------------------------------------------
Unamortized debt (discount), net (61) (64)
- ----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $509 million) 7,910 7,580
Less amount due within one year 67 329
- ----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 7,843 7,251 37.1% 38.0%
- ----------------------------------------------------------------------------------------------------------------------------
II-22
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2000 and 1999
Southern Company and Subsidiary Companies 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------
(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% 297 297
7.60% to 7.63% 415 415
7.75% 649 649
8.14% to 8.19% 400 400
Auction rate (6.52% at 1/1/01) 50 50
- ---------------------------------------------------------------------------------------------------------------------------
Total company or subsidiary obligated mandatorily
redeemable capital and preferred securities (annual
distribution requirement -- $169 million) 2,246 2,246 10.6 11.8
- ---------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
4.20% to 7.00% 98 99
$25 par or stated value --
5.20% to 5.83% 200 200
Adjustable and auction rates -- at 1/1/01:
5.14% to 5.25% 70 70
- ---------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock of subsidiaries
(annual dividend requirement -- $19 million) 368 369 1.7 1.9
- ---------------------------------------------------------------------------------------------------------------------------
Common Stockholders' Equity:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Issued -- 2000: 701 million shares
-- 1999: 701 million shares
Treasury -- 2000: 19 million shares
-- 1999: 35 million shares
Par value 3,503 3,503
Paid-in capital 3,153 2,480
Treasury, at cost (545) (919)
Retained earnings 4,672 4,232
Accumulated other comprehensive income
from discontinued operations (93) (92)
- ---------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity 10,690 9,204 50.6 48.3
- ---------------------------------------------------------------------------------------------------------------------------
Total Capitalization $21,147 $19,070 100.0% 100.0%
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-23
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2000, 1999, and 1998
Southern Company and Subsidiary Companies 2000 Annual Report
Accumulated
Other
Comprehensive
Common Stock Income
------------------------------------- From
Par Paid In Retained Discontinued
Value Capital Treasury Earnings Operations Total
- -------------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at January 1, 1998 $3,467 $2,331 $ - $3,842 $ 7 $ 9,647
Net income - - - 977 - 977
Other comprehensive income - - - - 8 8
Stock issued 32 132 70 - - 234
Stock repurchased, at cost - - (125) - - (125)
Cash dividends - - - (933) - (933)
Other - - (3) (8) - (11)
- -------------------------------------------------------------------------------------------------------------------------------
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 - - 910 - - 910
Stock repurchased, at cost - - (414) - - (414)
Cash dividends - - - (873) - (873)
Other - 673 (122) - - 551
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 $3,503 $3,153 $ (545) $4,672 $ (93) $10,690
===============================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Southern Company and Subsidiary Companies 2000 Annual Report
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
(in millions)
Consolidated Net Income $1,313 $1,276 $977
Other comprehensive income from discontinued operations,
net of minority interest:
Foreign currency translation adjustments (2) (165) 12
Less applicable income taxes (benefits) (1) (58) 4
- -------------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income $1,312 $1,169 $985
===============================================================================================================================
The accompanying notes are an integral part of these statements.
II-24
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2000 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Southern Company is the parent company of five integrated Southeast utilities, a
system service company, Southern Communications Services (Southern LINC),
Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern
Nuclear), Mirant Corporation -- formerly Southern Energy, Inc. -- and other
direct and indirect subsidiaries. The integrated Southeast utilities -- Alabama
Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric --
provide electric service in four states. Contracts among the integrated
Southeast utilities -- related to jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission (SEC). The system service company provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the
integrated Southeast utilities and also markets these services to the public
within the Southeast. Southern Company Energy Solutions develops new business
opportunities related to energy products and services. Southern Nuclear provides
services to Southern Company's nuclear power plants. Mirant acquires, develops,
builds, owns, and operates power production and delivery facilities and provides
a broad range of energy-related services to utilities and industrial companies
in selected countries around the world. Mirant businesses include independent
power projects, integrated utilities, a distribution company, and energy trading
and marketing businesses outside the southeastern United States. As a result of
the approved spin off of Mirant, Southern Company's financial statements and
related information, both current and historical, 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 integrated Southeast
utilities 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 integrated Southeast utilities 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:
2000 1999
- ---------------------------------------------------------------
(in millions)
Deferred income tax charges $ 957 $ 987
Premium on reacquired debt 280 302
Department of Energy assessments 46 52
Vacation pay 92 87
Postretirement benefits 30 33
Deferred income tax credits (551) (640)
Accelerated amortization (220) (85)
Storm damage reserves (34) (29)
Other, net 116 144
- ---------------------------------------------------------------
Total $ 716 $ 851
===============================================================
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.
II-25
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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 integrated Southeast utilities 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.
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 $136
million in 2000, $137 million in 1999, and $133 million in 1998. 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 fuel in January 1998 as required by the contracts, and
the companies are pursuing legal remedies against the government for breach of
contract. Effective June 2000, an on-site dry storage facility for Plant Hatch
became operational. Sufficient capacity is believed to be available to continue
dry storage operations at Plant Hatch through the life of the plant. Sufficient
fuel storage capacity currently is available at Plant Vogtle to maintain
full-core discharge capability for both units into the year 2014. 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. Alabama Power and Georgia Power -- based
on its ownership interests -- estimate their respective remaining liability at
December 31, 2000, under this law to be approximately $25 million and $19
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 in both 2000
and 1999 and 3.3 percent in 1998. 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
$135 million in 2000, $85 million in 1999, and $314 million in 1998. See Note 3
under "Georgia Power 1998 Retail Rate Order" for additional information.
The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial 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-26
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
of December 31, 2000, 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.
Georgia Power has filed with the NRC an application requesting a 20-year
renewal of the licenses for both units at Plant Hatch, which would permit the
operation of both units until 2034.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 2000 and fund balances were as follows:
Plant Plant Plant
Farley Hatch Vogtle
- ---------------------------------------------------------------
(in millions)
Amount expensed in 2000 $ 18 $ 19 $ 9
Accumulated provisions:
External trust funds,
at fair value $314 $230 $146
Internal reserves 38 20 12
- ---------------------------------------------------------------
Total $352 $250 $158
===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site
study. Effective January 1, 1999, the Georgia Public Service Commission (GPSC)
increased Georgia Power's annual provision for decommissioning expenses TO $28
million. This amount is based on the NRC generic estimate to decommission the
radioactive portion of the facilities as of 1997. The estimates are $526 million
and $438 million for plants Hatch and Vogtle, respectively. The ultimate costs
associated with the 1997 NRC minimum funding requirements are $1.1 billion and
$1.3 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.
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 used during construction was
$71 million in 2000, $36 million in 1999, and $19 million in 1998. 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.
Leveraged Leases
Southern Company has several leveraged lease agreements -- ranging up to 30
years -- that primarily relate to energy generation, distribution, and
transportation assets. The investment income earned from these leveraged leases
is immaterial for all periods presented.
II-27
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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 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 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 foreign currency
translation adjustments, net of taxes -- is presented in the consolidated
financial statements. The objective of the statement 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 for Non-Trading Activities
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.
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 company is
unaware of any counterparties that will fail to meet their obligations.
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 notional amount is
32 million euros maturing in 2001 through 2002. At December 31, 2000, the
unrecognized gain on these swaps was approximately $3 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, 2000 $7,815 $7,702
At December 31, 1999 7,483 7,046
Capital and preferred securities:
At December 31, 2000 2,246 2,190
At December 31, 1999 2,246 1,942
- ------------------------------------------------------------------
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 defined benefit, trusteed, pension plans that cover
substantially all employees. Southern 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 integrated Southeast
utilities fund trusts to the extent required by their respective regulatory
commissions. In late 2000, Southern Company adopted several pension and
postretirement benefits plan changes that had the effect of increasing benefits
to both current and future retirees. The effects of these changes will be to
increase annual pension and postretirement benefits costs by approximately
$28 million and $26 million, respectively.
II-28
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
The measurement date for plan assets and obligations is September 30 for each
year. The following disclosures exclude discontinued operations.
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
---------------------
2000 1999
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $3,098 $3,084
Service cost 94 95
Interest cost 227 204
Benefits paid (145) (143)
Actuarial (gain) loss (28) (142)
- ----------------------------------------------------------------
Balance at end of year $3,246 $3,098
================================================================
Plan Assets
-------------------
2000 1999
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $5,266 $4,646
Actual return on plan assets 1,030 771
Benefits paid (139) (151)
- ----------------------------------------------------------------
Balance at end of year $6,157 $5,266
================================================================
The accrued pension costs recognized in the Consolidated Balance
as follows:
2000 1999
- ---------------------------------------------------------------
(in millions)
Funded status $ 2,911 $ 2,168
Unrecognized transition obligation (64) (77)
Unrecognized prior service cost 97 106
Unrecognized net gain (2,446) (1,829)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 498 $ 368
===============================================================
Components of the pension plans' net periodic cost were as follows:
2000 1999 1998
- --------------------------------------------------------------
(in millions)
Service cost $ 94 $ 95 $ 86
Interest cost 227 204 204
Expected return on
plan assets (384) (348) (320)
Recognized net gain (64) (41) (47)
Net amortization (3) (4) (3)
- --------------------------------------------------------------
Net pension cost (income) $(130) $ (94) $ (80)
==============================================================
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
--------------------
2000 1999
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $ 980 $1,029
Service cost 18 21
Interest cost 76 68
Benefits paid (43) (36)
Actuarial (gain) loss 21 (102)
- ---------------------------------------------------------------
Balance at end of year $1,052 $ 980
===============================================================
Plan Assets
------------------
2000 1999
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $395 $336
Actual return on plan assets 47 36
Employer contributions 59 60
Benefits paid (42) (37)
- ---------------------------------------------------------------
Balance at end of year $459 $395
===============================================================
The accrued postretirement costs recognized in the Consolidated Balance
Sheets were as follows:
2000 1999
- ---------------------------------------------------------------
(in millions)
Funded status $(593) $(585)
Unrecognized transition obligation 189 203
Unrecognized prior service cost 66 -
Unrecognized net loss (gain) (53) 10
Fourth quarter contributions 35 26
- ---------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $(356) $(346)
===============================================================
Components of the postretirement plans' net periodic cost were as follows:
2000 1999 1998
- --------------------------------------------------------------
(in millions)
Service cost $ 18 $ 21 $ 18
Interest cost 76 68 68
Expected return on
plan assets (34) (26) (21)
Recognized net gain - 2 2
Net amortization 18 15 15
- --------------------------------------------------------------
Net postretirement cost $ 78 $ 80 $ 82
==============================================================
II-29
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
The weighted average rates assumed in the actuarial calculations
for both the pension plans and postretirement benefits were:
2000 1999
- ---------------------------------------------------------------
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 7.29
percent for 2000, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2000 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $71 $63
Service and interest costs 6 6
- ---------------------------------------------------------------
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 2000, 1999, and 1998 were
$49 million, $46 million, and $43 million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power and four other unrelated entities were notified
by the Environmental Protection Agency (EPA) that they have been designated as
potentially responsible parties under the Comprehensive Environmental Response,
Compensation, and Liability Act with respect to a site in Brunswick, Georgia. As
of December 31, 2000, Georgia Power had recorded approximately $5 million in
cumulative expenses associated with Georgia Power's agreed-upon share of the
removal and remedial investigation and feasibility study costs for this site.
The final outcome of this matter cannot now be determined. However, based on
the nature and extent of Georgia Power's activities relating to the site,
management believes that the company's portion of any remaining remediation
costs should not be material to the financial statements.
Environmental Litigation
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
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, 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 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 the system service
company's motion to dismiss on the grounds that it neither owned nor operated
the generating units involved in the proceedings. On January 12, 2001, the EPA
re-filed its claims against Alabama Power in federal district court in
Birmingham, Alabama. The EPA did not include the system service company in the
new complaint. Southern Company believes that its integrated utilities complied
with applicable laws and the EPA's regulations and interpretations in effect at
the time the work in question took place.
II-30
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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.
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
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, 2000, MESH had total
assets of $373 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, 2000, 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, 2000. 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
bankruptcy court. The proposed plan of reorganization was again amended on
February 21, 2001. Changes in circumstances since the filing of the amended plan
may require further modifications of the plan. Southern Company expects that
approval of a plan of reorganization would result in a termination of Southern
Company's ownership interest in MESH, but would not affect Southern Company's
continuing guarantee obligations described earlier. The final outcome of this
matter cannot now be determined.
California Electricity Markets Litigation
Five lawsuits have been 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. Four of the suits seek class action status. One lawsuit
naming Southern Company, Mirant, and other generators as defendants alleges
that, as a result of the defendants' conduct, customers paid approximately $4
billion more for electricity than they otherwise would have and seeks an award
of treble damages, as well as other injunctive and equitable relief. The other
suits likewise seek treble damages and equitable relief. While two of the suits
name Southern Company as a defendant, it appears that the allegations, as they
may relate to Southern Company, are directed to activities of subsidiaries of
Mirant. One such suit names Mirant itself as a defendant. Southern Company has
notified Mirant of its claim for indemnification for costs associated with these
actions under the terms of the master separation agreement that governs the spin
off of Mirant. Mirant has undertaken the defense of all of the claims. The final
outcome of these lawsuits cannot now be determined.
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 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 and a new defendant, Southern Company Energy Solutions,
Inc. The lawsuit is in the discovery phase. The final outcome of this matter
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
II-31
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
on end-of-period retail common equity. The rates also provide for adjustments to
recognize the placing of new generating facilities in retail service. Both
increases and decreases have been placed into effect since the adoption of these
rates. The rate adjustment procedures allow a return on common equity range of
13 percent to 14.5 percent and limit increases or decreases in rates to 4
percent in any calendar year. There is a moratorium on any periodic retail rate
increases (but not decreases) until July 2001.
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. In April
1997, the APSC issued an additional order authorizing Alabama Power to reduce
balance sheet asset items. This order authorizes the reduction of such items up
to an amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by Alabama Power. In 1998,
Alabama Power -- in accordance with the 1995 rate order -- recorded $33 million
of additional amortization of premium on reacquired debt. Alabama Power did not
record any additional amounts in 2000 or 1999.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Georgia Power 1998 Retail Rate Order
As required by the GPSC, Georgia Power filed a general rate case in 1998. On
December 18, 1998, the GPSC approved a three-year rate order for Georgia Power
ending December 31, 2001. Under the terms of the order, Georgia Power's earnings
will continue to be evaluated against a retail return on common equity range of
10 percent to 12.5 percent. Georgia Power's annual retail rates were decreased
by $262 million effective January 1, 1999, and by an additional $24 million
effective January 1, 2000. In addition, the order provided for $85 million
annually to be applied to accelerated amortization or depreciation of assets,
and up to an additional $50 million annually in 2000 and 2001 of any earnings
above the 12.5 percent return. In accordance with the rate order, Georgia Power
recorded accelerated amortization of $135 million and $85 million in 2000 and
1999, respectively. In May 2000, the GPSC ordered that these funds be maintained
in a regulatory liability account and ordered that interest be accrued on this
account at the prime rate. In 2000, interest of $10 million was recorded. These
amounts are reflected on the balance sheets in deferred credits and other
liabilities, other.
Two-thirds of any additional earnings above the 12.5 percent return in any
year will be applied to rate reductions and the remaining one-third retained by
Georgia Power. In both 2000 and 1999, Georgia Power's return was above 12.5
percent, and accordingly, it recorded in 1999 $79 million of revenues to be
refunded to customers in 2000. In 2000, Georgia Power recorded $44 million as an
estimate of revenues to be refunded in 2001. Georgia Power is required to file a
general rate case on July 1, 2001. At that time, the GPSC is expected to
determine whether the rate order should be continued, modified, or discontinued.
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.
At December 31, 2000, 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% $3,301 $1,724
Plant Hatch
(nuclear) 50.1 873 650
Plant Miller
(coal)
Units 1 and 2 91.8 743 312
Plant Scherer
(coal)
Units 1 and 2 8.4 112 53
Plant Wansley
(coal) 53.5 300 150
Rocky Mountain
(pumped storage) 25.4 169 72
Intercession City
(combustion turbine) 33.3 11 1
- ---------------------------------------------------------------
II-32
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
Alabama Power and Georgia 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 integrated Southeast utilities 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 2000 with a minimum of three years notice -- until the expiration
of the contracts in 2010. Capacity revenues from unit power sales amounted to
$177 million in 2000, $174 million in 1999, and $196 million in 1998.
During 2000, Georgia Power and Mississippi Power entered into certain
operating leases for portions of their generating unit capacity. Capacity
revenues from these operating leases amounted to $20 million in 2000 and are
included in the financial statements as sales for resale. Minimum future
capacity revenues from noncancelable operating leases as of December 31, 2000
are as follows:
Year Amounts
- ----- -----------
(in millions)
2001 $ 53
2002 66
2003 66
2004 66
2005 27
2006 and thereafter 114
- ----------------------------------------------------------------
Total $392
================================================================
6. Income Taxes
At December 31, 2000, the tax-related regulatory assets and liabilities were
$957 million and $551 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:
2000 1999 1998
- ---------------------------------------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $ 421 $ 504 $ 548
Deferred 95 11 23
- ---------------------------------------------------------------
516 515 571
- ---------------------------------------------------------------
State --
Current 71 85 102
Deferred 1 (1) (3)
- ---------------------------------------------------------------
72 84 99
- ---------------------------------------------------------------
Total $ 588 $ 599 $ 670
===============================================================
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:
2000 1999
- ---------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $3,199 $3,088
Property basis differences 1,105 1,175
Other 650 444
- ---------------------------------------------------------------
Total 4,954 4,707
- ---------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 111 113
Other property basis differences 206 221
Deferred costs 190 102
Pension and other benefits 125 121
Other 231 198
- ---------------------------------------------------------------
Total 863 755
- ---------------------------------------------------------------
Net deferred tax liabilities 4,091 3,952
Portion included in current assets, net (17) (68)
- ---------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheets $4,074 $3,884
===============================================================
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
II-33
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
in 2000, $30 million in 1999, and $38 million in 1998. At December 31, 2000, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
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:
2000 1999 1998
- ---------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.4 3.8 3.8
Non-deductible book
depreciation 1.7 1.9 4.0
Difference in prior years'
deferred and current tax rate (1.3) (1.3) (1.3)
Other (2.1) (0.3) (1.6)
- ---------------------------------------------------------------
Effective income tax rate 36.7% 39.1% 39.9%
===============================================================
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.
7. Common Stock
Stock Issued and Repurchased
The amount and timing of additional equity capital to be raised in 2001 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital may be provided from any combination of
public offerings, private placements, or the company's stock plans.
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. Funding for the program was provided from Southern Company's
commercial paper program.
Shares Reserved
At December 31, 2000, a total of 59 million shares was reserved for issuance
pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside
Directors Stock Plan, and the Performance Stock Plan.
Performance Stock Plan
The performance stock plan provides non-qualified stock options to a large
segment of Southern Company's employees ranging from line management to
executives. As of December 31, 2000, 5,744 current and former employees
participated in the plan. The maximum number of shares of common stock that may
be issued under the plan may not exceed 40 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 activity in 1999 and 2000 for the plan is summarized below:
Shares Average
Subject Option Price
To Option Per Share
- ---------------------------------------------------------------
Balance at December 31, 1998 6,445,398 $22.77
Options granted 2,108,818 26.56
Options canceled (28,630) 25.48
Options exercised (56,708) 19.51
- ---------------------------------------------------------------
Balance at December 31, 1999 8,468,878 23.73
Options granted 6,977,038 23.25
Options canceled (226,597) 23.66
Options exercised (984,897) 21.63
- ---------------------------------------------------------------
Balance at December 31, 2000 14,234,422 $23.63
===============================================================
Shares reserved for future grants:
At December 31, 1998 36,598,001
At December 31, 1999 34,515,156
At December 31, 2000 27,750,261
- ---------------------------------------------------------------
Options exercisable:
At December 31, 1999 4,525,349
At December 31, 2000 5,898,698
- ---------------------------------------------------------------
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-34
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
The following table summarizes information about options outstanding at
December 31, 2000:
Price Range of Options
--------------------------
14-20 21-24 25-28
- --------------------------------------------------------------
Outstanding:
Shares (in thousands) 430 10,217 3,587
Average remaining
life (in years) 2.5 8.2 8.1
Average exercise price $17.36 $22.79 $26.77
Exerciseable:
Shares (in thousands) 424 3,653 1,822
Average exercise price $17.64 $21.96 $26.84
- --------------------------------------------------------------
The estimated fair values of stock options granted in 2000, 1999 and 1998
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:
2000 1999 1998
- -----------------------------------------------------------------
Interest rate 6.7% 5.8% 5.5%
Average expected life of
stock options (in years) 4.0 3.7 3.7
Expected volatility of
common stock 20.9% 20.7% 19.2%
Expected annual dividends
on common stock $1.34 $1.34 $1.34
Weighted average fair value
of stock options granted $3.36 $4.61 $4.27
- -----------------------------------------------------------------
The pro forma impact on earnings of fair-value accounting for options granted
- -- as required by FASB Statement No. 123, Accounting for Stock-Based
Compensation -- is 1.2 cents per share in 2000 and less than 1 cent in both 1999
and 1998.
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 Performance
Stock 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
-------------------------------
2000 1999 1998
- ---------------------------------------------------------------
(in thousands)
As reported shares 653,086 685,163 696,944
Effect of options 1,108 580 739
- ---------------------------------------------------------------
Diluted shares 654,194 685,743 697,683
===============================================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 2000, consolidated retained earnings included
$3.5 billion of undistributed retained earnings of the subsidiaries. Of this
amount, $2.0 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures.
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, 2000, capital securities of
$950 million and preferred securities of $1.3 billion were outstanding. Southern
Company guarantees the notes related to $950 million of capital or preferred
securities issued on its behalf.
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:
2000 1999
- --------------------------------------------------------------
(in millions)
Bond improvement fund requirements $11 $ 14
Less:
Portion to be satisfied by certifying
property additions 11 9
- --------------------------------------------------------------
Cash requirements - 5
First mortgage bond maturities
and redemptions - 200
Other long-term debt maturities 67 124
- --------------------------------------------------------------
Total $67 $329
==============================================================
The first mortgage bond improvement fund requirements amount to 1 percent of
each outstanding series of bonds authenticated under the indentures prior to
II-35
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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 166 2/3 percent of such requirements.
With respect to the collateralized pollution control revenue bonds, the
integrated Southeast utilities 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 2005
applicable to other long-term debt are as follows: $67 million in 2001; $489
million in 2002; $479 million in 2003; $323 million in 2004; and $600 million in
2005.
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. 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 2001, unused credit arrangements with banks totaled $5.1
billion, of which $3.2 billion expires during 2001, $1.0 billion during 2002,
and $900 million during 2003 and 2004. The following table outlines the credit
arrangements by company:
Amount of Credit
-----------------------------------
Expires
---------------
2002 &
Company Total Unused 2001 beyond
- ------- ------------------------------------
(in millions)
Alabama Power $ 925 $ 925 $ 535 $ 390
Georgia Power 1,765 1,765 1,265 500
Gulf Power 123 115 115 -
Mississippi Power 117 117 117 -
Savannah Electric 65 50 40 10
Southern Company 2,100 2,100 1,100 1,000
Other 60 51 51 -
- --------------------------------------------------------------
Total $5,155 $5,123 $3,223 $1,900
==============================================================
Approximately $2.9 billion of the credit facilities 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. Of the total $5.1 billion in unused credit, $2.1 billion, $1.65
billion, and $780 million are syndicated credit arrangements of Southern
Company, Georgia Power, and Alabama Power, respectively. These facilities also
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, 2000, was $1.6 billion.
Southern Company, Alabama Power, and Georgia Power 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.
9. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently
estimated to total $2.9 billion in 2001, $2.6 billion in 2002, and $1.7
billion in 2003. 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, 2000, significant purchase commitments were outstanding in connection
with the construction program. Southern Company has approximately 6,300
megawatts of additional generating capacity scheduled to be placed in
service by 2003.
See Management's Discussion and Analysis under "Environmental Matters" for
II-36
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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.
Also, Southern Company has entered into various long-term commitments for the
purchase of electricity. Total estimated long-term obligations at December 31,
2000, were as follows:
Purchased
Year Fuel Power
- ---- -------------------------
(in millions)
2001 $ 2,481 $ 81
2002 1,897 97
2003 1,711 99
2004 1,328 95
2005 1,055 95
2006 and thereafter 3,764 693
- --------------------------------------------------------------
Total commitments $12,236 $1,160
==============================================================
Operating Leases
Southern Company has operating lease agreements with various terms and
expiration dates. These expenses totaled $42 million, $35 million, and $26
million for 2000, 1999, and 1998, respectively. At December 31, 2000, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
- ---- ------------
(in millions)
2001 $ 57
2002 71
2003 71
2004 68
2005 64
2006 and thereafter 388
- --------------------------------------------------------------
Total minimum payments $719
==============================================================
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, 2000, the total notional amount of
guarantees was $419 million and the estimated fair value of net contractual
commitments outstanding was approximately $259 million. 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.
At December 31, 2000, Southern Company had guaranteed $11 million related to
a Mirant purchase power agreement. The guarantee expires March 2001.
Southern Company also has guaranteed certain of Mirant's foreign currency swap
transactions. At December 31, 2000, notional amounts under these swaps were the
differences between (pound)44 million and $68 million and between DM370 million
and $206 million; however, due to favorable exchange ratesSouthern Company had
no exposure under these guarantees. The sterling and deutsche mark swaps expire
in 2002 and 2003, respectively.
After the spin off, Mirant will pay Southern Company a monthly fee of 1
percent on the average aggregate maximum principal amount of all guarantees
outstanding until they are replaced or expire. Southern Company's guarantees
related to Mirant trading and marketing activities are limited to a maximum
of $425 million, with any guarantees since October 2, 2000 expiring no later
than October 2, 2001. 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 private insurance, 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.
II-37
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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 be insured against increased costs of replacement power in an
amount up to $3.5 million per week -- starting 12 weeks after the outage -- for
one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if losses
each year exceed the accumulated funds available to the insurer under that
policy. The current maximum annual assessments for Alabama Power and Georgia
Power under the three NEIL policies would be $17 million and $19 million,
respectively.
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.
11. DISCONTINUED 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 an 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, Southern Company's board of directors approved the
spin off of its remaining ownership of 272 million Mirant shares to be
completed in a tax free distribution on April 2, 2001. Shares from the spin off
will be distributed at a ratio of approximately 0.4 for every share of
Southern Company common stock held at record date.
As a result of the spin off, Southern Company's December 31, 2000, financial
statements have been prepared with Mirant's results of operations and cash flows
shown as discontinued operations. All historical financial statements presented
and footnotes have been reclassified to conform to this presentation, with the
historical assets and liabilities of Mirant presented on the balance sheet as
net assets of discontinued operations.
Summarized financial information for the discontinued operations is as
follows at December 31:
2000 1999 1998
- ---------------------------------------------------------------
(in millions)
Revenues $13,315 $2,265 $1,819
Income taxes 86 127 (121)
Net income 319 361 (9)
- ---------------------------------------------------------------
2000 1999
- ---------------------------------------------------------------
(in millions)
Current assets $ 9,057 $ 1,254
Total assets 22,377 12,191
Current liabilities 9,726 3,169
Total liabilities 17,585 8,473
Minority and other interests 1,472 805
Net assets of
discontinued operations 3,320 2,913
- ---------------------------------------------------------------
12. SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segment is the five integrated Southeast
utilities that provide electric service in four states. 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
II-38
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
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
Integrated
Southeast 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 43 9 (1) 51
Interest expense 631 197 - 828
Income taxes 703 (115) - 588
Segment net income (loss) 1,109 (115) 319 1,313
Total assets 26,917 2,200 2,245 31,362
Gross property additions 2,199 26 - 2,225
- -------------------------------------------------------------------------------------------------------------------------------
Integrated
Southeast 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 64 50 (44) 70
Interest expense 613 155 (37) 731
Income taxes 675 (76) - 599
Segment net income (loss) 1,073 (154) 357 1,276
Total assets 25,336 2,127 1,828 29,291
Gross property additions 1,854 27 - 1,881
- -------------------------------------------------------------------------------------------------------------------------------
II-39
NOTES (continued)
Southern Company and Subsidiary Companies 2000 Annual Eeport
Integrated
Southeast All Reconciling
Year Utilities Other Eliminations Consolidated
- ----- ------------------------------------------------------------------------------------
(in millions)
1998
- ----
Operating revenues $ 9,363 $ 167 $ (31) $ 9,499
Depreciation and amortization 1,323 17 - 1,340
Interest income 150 58 (54) 154
Interest expense 654 99 (54) 699
Income taxes 703 (33) - 670
Segment net income (loss) 1,083 (97) (9) 977
Total assets 24,420 2,817 1,486 28,723
Gross property additions 1,298 58 - 1,356
- -------------------------------------------------------------------------------------------------------------------------------
Products and Services
Integrated Southeast Utilities Revenues
--------------------------------------------------------------------------------------------
Year Retail Wholesale Other Total
- ---- -------------------------------------------------------------------------------------------
(in millions)
2000 $8,613 $977 $270 $9,860
1999 8,086 823 216 9,125
1998 8,272 896 195 9,363
- -------------------------------------------------------------------------------------------------------------------------------
13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2000 and 1999 -- including discontinued
operations for net income and earnings per share -- are as follows:
Per Common Share
----------------------------------------------------
Operating Operating Consolidated Price Range
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
- ------------- ------------------------------------ -----------------------------------------------------
(in millions)
March 2000 $2,052 $ 428 $245 $0.38 $0.335 25 7/8 20 3/8
June 2000 2,522 598 342 0.52 0.335 27 7/8 21 11/16
September 2000 3,198 1,041 614 0.95 0.335 35 23 13/32
December 2000 2,294 337 112 0.16 0.335 33 22/25 27 1/2
March 1999 $1,920 $ 408 $224 $0.32 $0.335 29 5/8 23 1/4
June 1999 2,288 569 314 0.45 0.335 29 3/16 22 3/4
September 1999 3,050 981 615 0.90 0.335 28 25
December 1999 2,059 292 123 0.19 0.335 27 1/8 22 1/16
- -----------------------------------------------------------------------------------------------------------------------
Southern Company's business is influenced by seasonal weather conditions.
II-40
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1996-2000
Southern Company and Subsidiary Companies 2000 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $10,066 $9,317 $9,499 $8,774 $8,675
Total Assets (in millions) $31,362 $29,291 $28,723 $27,898 $26,352
Gross Property Additions (in millions) $2,225 $1,881 $1,356 $1,138 $1,064
Return on Average Common Equity (percent) 13.20 13.43 10.04 10.30 12.53
Cash Dividends Paid Per Share of Common Stock $1.34 $1.34 $1.34 $1.30 $1.26
- -------------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income (in millions):
Continuing operations $ 994 $ 915 $986 $990 $1,046
Discontinued operations 319 361 (9) (18) 81
- -------------------------------------------------------------------------------------------------------------------------------
Total $1,313 $1,276 $977 $972 $1,127
===============================================================================================================================
Basic and Diluted Earnings Per Share of Common Stock:
Continuing operations $1.52 $1.33 $ 1.41 $ 1.45 $1.56
Discontinued operations 0.49 0.53 (0.01) (0.03) 0.12
- -------------------------------------------------------------------------------------------------------------------------------
Total $2.01 $1.86 $ 1.40 $1.42 $1.68
===============================================================================================================================
Capitalization (in millions):
Common stock equity $10,690 $ 9,204 $ 9,797 $ 9,647 $ 9,216
Preferred stock and securities 2,614 2,615 2,465 2,155 1,402
Long-term debt 7,843 7,251 6,505 6,347 6,556
- -------------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $21,147 $19,070 $18,767 $18,149 $17,174
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 50.6 48.3 52.2 53.2 53.7
Preferred stock and securities 12.3 13.7 13.1 11.9 8.2
Long-term debt 37.1 38.0 34.7 34.9 38.1
- -------------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0 100.0 100.0
===============================================================================================================================
Other Common Stock Data:
Book value per share (year-end) $15.69 $13.82 $14.04 $13.91 $13.61
Market price per share:
High 35 29 5/8 31 9/16 26 1/4 25 7/8
Low 20 3/8 22 1/16 23 15/16 19 7/8 21 1/8
Close 33 1/4 23 1/2 29 1/16 25 7/8 22 5/8
Market-to-book ratio (year-end) (percent) 211.9 170.0 207.0 186.0 166.2
Price-earnings ratio (year-end) (times) 16.5 12.6 20.8 18.2 13.5
Dividends paid (in millions) $873 $921 $933 $889 $846
Dividend yield (year-end) (percent) 4.0 5.7 4.6 5.0 5.6
Dividend payout ratio (percent) 66.5 72.2 95.6 91.5 75.1
Shares outstanding (in thousands):
Average 653,087 685,163 696,944 685,033 672,590
Year-end 681,158 665,796 697,747 693,423 677,036
Stockholders of record (year-end) 160,116 174,179 187,053 200,508 215,246
- -------------------------------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 3,398 3,339 3,277 3,220 3,157
Commercial 527 513 497 479 464
Industrial 14 15 15 16 17
Other 5 4 5 5 5
- -------------------------------------------------------------------------------------------------------------------------------
Total 3,944 3,871 3,794 3,720 3,643
===============================================================================================================================
Employees (year-end) 26,021 26,269 25,206 24,682 25,034
- -------------------------------------------------------------------------------------------------------------------------------
II-41
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1996-2000 (continued)
Southern Company and Subsidiary Companies 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $ 3,367 $3,105 $3,163 $2,837 $2,894
Commercial 2,922 2,743 2,763 2,595 2,559
Industrial 2,292 2,237 2,267 2,139 2,136
Other 32 1 79 76 76
- -----------------------------------------------------------------------------------------------------------------------
Total retail 8,613 8,086 8,272 7,647 7,665
Sales for resale within service area 377 350 374 376 409
Sales for resale outside service area 600 473 522 510 429
- -----------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 9,590 8,909 9,168 8,533 8,503
Other revenues 476 408 331 241 172
- -----------------------------------------------------------------------------------------------------------------------
Total $10,066 $9,317 $9,499 $8,774 $8,675
=======================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 46,213 43,402 43,503 39,217 40,117
Commercial 46,249 43,387 41,737 38,926 37,993
Industrial 56,746 56,210 55,331 54,196 52,798
Other 970 945 929 903 911
- -----------------------------------------------------------------------------------------------------------------------
Total retail 150,178 143,944 141,500 133,242 131,819
Sales for resale within service area 9,579 9,440 9,847 9,884 10,935
Sales for resale outside service area 17,190 12,929 12,988 13,761 10,777
- -----------------------------------------------------------------------------------------------------------------------
Total 176,947 166,313 164,335 156,887 153,531
=======================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.29 7.15 7.27 7.23 7.21
Commercial 6.32 6.32 6.62 6.67 6.74
Industrial 4.04 3.98 4.10 3.95 4.04
Total retail 5.74 5.62 5.85 5.74 5.81
Sales for resale 3.65 3.68 3.92 3.75 3.86
Total sales 5.42 5.36 5.58 5.44 5.54
Average Annual Kilowatt-Hour
Use Per Residential Customer 13,702 13,107 13,379 12,296 12,824
Average Annual Revenue Per Residential Customer $998.38 $937.81 $972.89 $889.50 $925.12
Plant Nameplate Capacity Owned (year-end) (megawatts) 32,807 31,425 31,161 31,146 31,076
Maximum Peak-Hour Demand (megawatts):
Winter 26,370 25,203 21,108 22,969 22,631
Summer 31,359 30,578 28,934 27,334 27,190
System Reserve Margin (at peak) (percent) 8.1 8.5 12.8 15.0 14.0
Annual Load Factor (percent) 60.2 59.2 60.0 59.4 62.3
Plant Availability (percent):
Fossil-steam 86.8 83.3 85.2 88.2 86.4
Nuclear 90.5 89.9 87.8 88.8 89.7
- -----------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.3 73.1 72.8 74.7 73.3
Nuclear 15.1 15.7 15.4 16.5 16.7
Hydro 1.5 2.3 3.9 4.3 4.1
Oil and gas 4.0 2.8 3.3 1.7 1.5
Purchased power 7.1 6.1 4.6 2.8 4.4
- -----------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
=======================================================================================================================
II-42
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-43
MANAGEMENT'S REPORT
Alabama Power Company 2000 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 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/Elmer B. Harris
Elmer B. Harris
President
and Chief Executive Officer
/s/William B. Hutchins, III
William B. Hutchins, III
Executive Vice President,
Chief Financial Officer, and Treasurer
II-44
REPORT OF INDEPENDENT PUBLIC ACCOUNTANT
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, 2000 and 1999, 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, 2000. 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-55 through II-73)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 2000 and 1999, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 28, 2001
II-45
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 2000 net income after dividends on preferred stock was
$420 million, representing a $20 million (5 percent) increase from the prior
year. This improvement is primarily attributable to an increase in territorial
sales partially offset by increased non-fuel operating expenses.
In 1999, earnings were $400 million, representing a 6 percent increase from
the prior year. This increase was due to a decrease in amortization related to
premiums paid to reacquire debt pursuant to an Alabama Public Service Commission
(APSC) order. See Note 3 to the financial statements under "Retail Rate
Adjustment Procedures" for additional details.
The return on average common equity for 2000 was 13.58 percent compared to
13.85 percent in 1999, and 13.63 percent in 1998.
Revenues
Operating revenues for 2000 were $3.7 billion, reflecting an increase from 1999.
The following table summarizes the principal factors that have affected
operating revenues for the past two years:
Increase (Decrease)
Amount From Prior Year
----------------------------------------
2000 2000 1999
- -------------------------------------------------------------------
(in thousands)
Retail --
Base revenues $2,108,939 $ 80,264 $ 10,022
Fuel cost recovery
and other 843,768 61,326 20,418
- -------------------------------------------------------------------
Total retail 2,952,707 141,590 30,440
- -------------------------------------------------------------------
Sales for resale --
Non affiliates 461,730 46,353 (33,596)
Affiliates 166,219 73,780 (11,123)
- -------------------------------------------------------------------
Total sales for resale 627,949 120,133 (44,719)
Other operating
revenues 86,805 20,264 13,380
- -------------------------------------------------------------------
Total operating
revenues $3,667,461 $281,987 $ (899)
===================================================================
Percent change 8.33% (0.03)%
- --------------------------------------------------------------------
Retail revenues of $3.0 billion in 2000 increased $142 million (5 percent)
from the prior year, compared with an increase of $30 million (1.1 percent) in
1999. The primary contributors to the increase in revenues in 2000 were the
positive impact of weather on energy sales, continued economic growth in the
Company's service territory, and an increase in fuel revenues. 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. Higher natural gas prices and decreased hydro production
combined with increased costs of purchased power have resulted in a large
under-recovery of fuel costs at December 31, 2000. Effective January 2001, the
Company's fuel rate was increased to address this under-recovery. The Company
expects to significantly reduce this balance over a three-year period.
II-46
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 Annual Report
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.
Retail revenues in 1999 increased $30 million (1.1 percent) over 1998. The
predominant factors causing the rise in revenues in 1999 were continued growth
in the Company's service territory, as well as an increase in fuel revenues.
These increases were offset by the effect of milder temperatures in 1999 as
compared to 1998.
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:
2000 1999 1998
---------------------------------------
(in millions)
Capacity $127 $122 $142
Energy 128 112 118
--------------------------------------------------------
Total $255 $234 $260
========================================================
Capacity revenues from non-affiliates were relatively unchanged in 2000
compared to the prior year. Capacity revenues from non-affiliates in 1999
decreased 13.9 percent compared to 1998. This decrease was attributable to the
lowering of the equity return under formula rate contracts, as well as other
adjustments and true-ups related to contractual pricing.
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 2000 and the percent change by year were as
follows:
KWH Percent Change
--------------------------------------
2000 2000 1999
--------------------------------------
(millions)
Residential 16,772 6.8% (0.6)%
Commercial 12,989 5.5 3.4
Industrial 22,101 0.7 1.7
Other 206 2.3 2.3
------------
Total retail 52,068 3.8 1.4
Sales for resale -
Non-affiliates 14,848 19.4 5.0
Affiliates 5,369 6.7 (15.8)
------------
Total 72,285 6.9% 0.5%
- ---------------------------------------------------------------
The increases in 2000 and 1999 retail energy sales were primarily due to the
strength of business and economic conditions in the Company's service area. In
2000, 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. Assuming normal weather, sales to retail customers
are projected to grow approximately 2.9 percent annually on average during 2001
through 2005.
Expenses
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.
In 1999, total operating expenses of $2.5 billion decreased $13 million or
0.5 percent compared with 1998. This decline was mainly due to a $15 million net
decrease in fuel and purchased power costs and a $23 million decrease in
maintenance expense, offset by an increase in taxes other than income taxes of
$12 million.
II-47
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 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:
--------------------------
2000 1999 1998
--------------------------
Total generation
(billions of KWHs) 65 63 63
Sources of generation
(percent) --
Coal 72 72 72
Nuclear 19 20 18
Hydro 3 5 8
Oil & Gas 6 3 2
Average cost of fuel per net
KWH generated
(cents) -- 1.54 1.44 1.54
- --------------------------------------------------------------
In 2000, total fuel and purchased power costs of $1.3 billion increased $183
million (16 percent), while total energy sales increased 4,658 million kilowatt
hours (6.9 percent) compared with the amounts recorded in 1999. Fuel and
purchased power costs in 1999 decreased $15 million (1 percent) compared to
1998.
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 2000, purchased power transactions among the
Company and non-affiliates increased $72 million (77 percent) due to higher
costs associated with these energy purchases and to offset decreased hydro
generation, which was down significantly compared to 1999 as a result of lower
stream flows.
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. The 7.5 percent decrease in maintenance expenses in 1999 is
primarily attributable to a decrease in distribution expenses.
Depreciation and amortization expense increased 4.9 percent in 2000 and 2.6
percent in 1999. These increases reflect additions to property, plant, and
equipment.
Taxes other than income taxes increased $5 million (2.5 percent) in 2000 as
compared to 1999. This increase is attributable to increases in real and
personal property taxes and public utility license taxes.
Total net interest and other charges increased $7 million (2.7 percent) in
2000. This increase results primarily from an increase in interest on long-term
debt offset by a decrease in other interest charges. Total net interest and
other charges decreased $38 million (12.3 percent) in 1999 primarily from a
decrease in the amortization of premiums on reacquired debt pursuant to an APSC
order. See Note 3 to the financial statements under "Retail Rate Adjustment
Procedures" for additional details.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility 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
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 of the Company to achieve
energy sales growth while containing cost in a more competitive environment.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
II-48
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 Annual Report
state of Alabama. Prices for electricity provided by the Company to retail
customers are set by the APSC under cost-based regulatory principles.
Future earnings for the traditional 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 Company's
traditional service area.
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 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 various restructuring and
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 current energy crisis in California. As a result of this
crisis, many states have either discontinued or delayed implementation of
initiatives involving retail deregulation. The inability of the Company to
recover its investments, including the regulatory assets described in Note 1 to
the financial statements, could have a material adverse effect on the Company's
financial statements.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the Company does not remain a low-cost producer and provide
quality service, then energy sales growth could be limited, and this could
significantly erode earnings.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encouraged utilities owning transmission systems to form RTOs on a voluntary
basis. After participating in the regional conferences with customers and other
members of the public to discuss the formation of RTOs, utilities were required
to make a filing with the FERC. Southern Company and its integrated southeast
utility subsidiaries, including the Company, filed on October 16, 2000, a
proposal for the creation of an RTO. The proposal is for the formation of a
for-profit company that would have control of the bulk power transmission system
of the Company and any other participating utilities. Participants would have
the option to either maintain their ownership, divest, sell, or lease their
assets to the proposed RTO. If the FERC accepts the proposal as filed, the
creation of an RTO is not expected to have a material impact on the Company's
financial statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to allow holding companies to form exempt wholesale generators to sell power
largely free of regulation under PUHCA. These entities are able to own and
operate power generating facilities and sell power to affiliates--under certain
restrictions.
The Company is constructing 1,230 megawatts of wholesale generating
facilities in Autaugaville, Alabama to begin operation in 2003. Half of this
capacity has been certified by the APSC to serve the Company's retail customers
II-49
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 Annual Report
for seven years. The other half of the capacity will be sold into the wholesale
market and will not affect retail rates.
Southern Company is aggressively working to maintain and expand its share of
wholesale sales in the southeastern power markets. In January 2001, Southern
Company announced the formation of a new subsidiary--Southern Power Company
(SPC). The new subsidiary will own, manage, and finance wholesale generating
assets in the Southeast. SPC will be the primary growth engine for Southern
Company's market-based energy business. Energy from its assets will be marketed
to wholesale customers under the Southern Company name.
Currently, the Company plans to transfer the generating facilities under
construction in Autaugaville to SPC in 2001. The Company will enter into a
purchased power agreement for half of the capacity of these generating
facilities to serve its territorial customers.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash income of
approximately $54 million in 2000. Pension plan income in 2001 is expected to be
less as a result of plan amendments. Future pension income is dependent on
several factors including trust earnings and changes to the plan. For more
information, see Note 2.
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. There is
a moratorium on any periodic retail rate increases (but not decreases) until
July 2001.
In December 1995, the APSC issued an order authorizing the Company to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the Company's actual base rate revenues exceed the budgeted revenues. In April
1997, the APSC issued an additional order authorizing the Company to reduce
balance sheet asset items. This order authorizes the reduction of such items up
to an amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the Company.
In 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 Company's wholesale
generating facilities under construction in Autaugaville, Alabama, all of which
will be delivered 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 in 2003 while the remaining half is
scheduled for delivery in 2004.
The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters."
The staff of the Securities and Exchange Commission (SEC) has questioned
certain of the current accounting practices of the electric utility industry --
including the Company -- regarding the recognition, measurement, and
classification in the financial statements of decommissioning costs for nuclear
generating facilities. In response to these questions, the FASB is reviewing the
accounting for liabilities related to the retirement of long-lived assets,
including nuclear decommissioning. If the FASB issues new accounting rules, the
estimated costs of retiring the Company's nuclear and other facilities may be
required to be recorded as liabilities in the Balance Sheets. Also, the annual
provisions for such costs could change. Because of the Company's current ability
to recover asset retirement costs through rates, these changes would not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.
The Company is subject to the provisions of FASB Statement No. 71,
Accounting for the Effects of Certain Types of Regulation. In the event that a
portion of the Company's operations is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets have been impaired. See Note 1 to the financial statements under
II-50
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 Annual Report
"Regulatory Assets and Liabilities" for additional information.
New Accounting Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No.
133, Accounting for Derivative Instruments and Hedging Activities.
Statement No. 133, as amended, establishes accounting and reporting
standards for derivative instruments and for hedging activities. Statement
No. 133 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 Company utilizes financial instruments to reduce its exposure to changes
in foreign currency exchange rates. The Company also enters into commodity
related forward 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 meet the
definition of a derivative under Statement No. 133. In many cases, these
transactions meet the normal purchase and sale exception and the related
contracts will continue to be accounted for under the accrual method. Certain of
these instruments qualify as cash flow hedges resulting in the deferral of
related gains and losses in other comprehensive income until the hedged
transactions occur. Any ineffectiveness will be recognized currently in net
income. However, others will be required to be marked to market through current
period income.
The Company adopted Statement No. 133 effective January 1, 2001, with no
material impact. The application of the new rules is still evolving and further
guidance from FASB is expected, which could additionally impact the Company's
financial statements.
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, 2000,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Also, based on the Company's
overall interest rate exposure at December 31, 2000, a near-term 100 basis point
change in interest rates would not materially affect the financial statements.
FINANCIAL CONDITION
Overview
The Company's financial condition remained stable in 2000. This stability is the
continuation over recent years of growth in retail energy sales and cost control
measures combined with a significant lowering of the cost of capital, achieved
through the refinancing and/or redemption of higher-cost long-term debt and
preferred stock.
The Company had gross property additions of $871 million in 2000. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.
Capital Structure
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.2 percent in 2000 and 42.4 percent in 1999 and 1998.
During 2000, the Company issued $250 million of senior notes, the proceeds
of which were used primarily to repay short-term indebtedness.
Capital Requirements
Capital expenditures are estimated to be $735 million for 2001, $891 million for
2002, and $625 million for 2003. 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,
II-51
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 Annual Report
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 stock and
replace these obligations with lower-cost capital if market conditions permit.
Environmental Matters
In November 1990, the Clean Air Act Amendments (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 integrated Southeast utility subsidiaries of
Southern Company, including 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 and some 50 generating plants
within the operating companies of Southern Company were brought into compliance
with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $25
million for the Company.
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 total construction expenditures through 2000 by $63 million
The one-hour ozone non-attainment standards for the Birmingham area have
been set and must be implemented in May 2003. Two generating plants will be
affected in the Birmingham area. Additional construction expenditures for
compliance with these new rules are currently estimated at approximately $230
million.
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 recently dismissed
certain challenges but 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 will address other legal challenges to
these standards in mid-2001. If the standards are eventually upheld,
implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide
reduction rules to the states for implementation. Compliance is required by May
31, 2004. The final rule affects 21 states including Alabama. If standards and
rules for implementation are upheld, the additional construction expenditures
for compliance are estimated at approximately $189 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. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
with respect to coal-fired generating facilities at the Company's Plants Miller,
Barry, and Gorgas. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The EPA concurrently issued a notice of
violation to the Company relating to these specific facilities, as well as
Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend
its complaint to add the violations alleged in its notice of violation. The
complaint and 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. On August 1, 2000, the U.S. District Court granted the Company's motion to
dismiss for lack of jurisdiction in Georgia and granted the system service
II-52
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 Annual Report
company's motion to dismiss on the grounds that it neither owned nor operated
the generating units involved in the proceedings. On January 12, 2001, the EPA
re-filed its claims against the Company in federal district court in Birmingham,
Alabama. The EPA did not include the system service company in the new
complaint. The Company believes that it complied with applicable laws and EPA
regulations and interpretations in effect at the time the work in question took
place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit. Prior to January 30, 1997, the penalty was
$25,000 per day. An adverse outcome of this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows, and possibly financial condition if such costs are not
recovered through regulated rates.
In December 2000, the EPA completed its utility studies 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 (MACT) provisions of the Clean Air Act. This determination is
being challenged in the courts. 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 would likely
be required around 2010. Litigation of the BART rules is probable in the near
future.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C.
add to the uncertainties associated with BART guidance and the MACT
determination for mercury and other HAPS.
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; 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
costs and will recognize in the financial statements costs to clean up known
sites. The Company has not incurred any 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, 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
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.
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2000 Annual Report
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," "expects," "plans," "anticipates,"
"believes," "estimates," "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 against the
Company; the extent and timing of the entry of additional competition in the
markets of the Company; potential business strategies, including acquisitions
or dispositions of assets or businesses, which cannot be assured to be
completed or beneficial; internal restructuring or other restructuring options,
that may be pursued by the Company; state and federal rate regulation in the
United States; political, legal and economic conditions and developments in
the United States; financial market conditions and the results of financing
efforts; the impact of fluctuations in commodity prices, interest rates and
customer demand; 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 SEC.
II-54
STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Alabama Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $2,952,707 $2,811,117 $2,780,677
Sales for resale --
Non-affiliates 461,730 415,377 448,973
Affiliates 166,219 92,439 103,562
Other revenues 86,805 66,541 53,161
- -----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,667,461 3,385,474 3,386,373
- -----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 963,275 855,632 900,309
Purchased power --
Non-affiliates 164,881 93,204 92,998
Affiliates 184,014 180,563 150,897
Other 538,529 531,696 527,954
Maintenance 301,046 277,724 300,383
Depreciation and amortization 364,618 347,574 338,822
Taxes other than income taxes 209,673 204,645 193,049
- -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,726,036 2,491,038 2,504,412
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income 941,425 894,436 881,961
Other Income (Expense):
Interest income 38,167 55,896 68,553
Equity in earnings of unconsolidated subsidiaries (Note 5) 3,156 2,650 5,271
Other, net (7,909) (24,861) (37,050)
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 974,839 928,121 918,735
- -----------------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 251,663 245,235 285,940
Distributions on preferred securities of subsidiary (Note 8) 25,549 24,662 22,354
- -----------------------------------------------------------------------------------------------------------------------------
Total interest and other, net 277,212 269,897 308,294
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 697,627 658,224 610,441
Income taxes (Note 7) 261,555 241,880 218,575
- -----------------------------------------------------------------------------------------------------------------------------
Net Income 436,072 416,344 391,866
Dividends on Preferred Stock 16,156 16,464 14,643
- -----------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 419,916 $ 399,880 $ 377,223
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-55
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
Alabama Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 436,072 $ 416,344 $ 391,866
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 412,998 403,332 425,167
Deferred income taxes and investment tax credits, net 66,166 29,039 79,430
Other, net (37,703) (12,661) (66,739)
Changes in certain current assets and liabilities --
Receivables, net (125,652) 33,509 49,747
Fossil fuel stock 23,967 (1,344) (9,052)
Materials and supplies (10,662) (17,968) 11,932
Accounts payable 107,702 (38,556) 26,583
Energy cost recovery, retail (69,190) (97,869) (95,427)
Other 23,336 5,930 (9,803)
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 827,034 719,756 803,704
- ----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (870,581) (809,044) (610,132)
Other (49,414) (72,218) (52,940)
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (919,995) (881,262) (663,072)
- ----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 184,519 96,824 (306,882)
Proceeds --
Other long-term debt 250,000 751,650 1,462,990
Preferred securities - 50,000 -
Preferred stock - - 200,000
Capital contributions from parent company 204,371 204,347 30,000
Redemptions --
First mortgage bonds (111,009) (470,000) (771,108)
Other long-term debt (5,987) (104,836) (107,776)
Preferred stock - (50,000) (88,000)
Payment of preferred stock dividends (16,110) (15,788) (15,596)
Payment of common stock dividends (417,100) (399,600) (367,100)
Other (951) (15,864) (66,869)
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from financing activities 87,733 46,733 (30,341)
- ----------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (5,228) (114,773) 110,291
Cash and Cash Equivalents at Beginning of Period 19,475 134,248 23,957
- ----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 14,247 $ 19,475 $ 134,248
==================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $237,066 $229,305 $234,360
Income taxes (net of refunds) 175,303 170,121 188,942
- ----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-56
BALANCE SHEETS
At December 31, 2000 and 1999
Alabama Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Assets 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 14,247 $ 19,475
Receivables --
Customer accounts receivable 337,870 265,900
Under-recovered retail fuel clause revenue 237,817 168,627
Other accounts and notes receivable 60,315 42,137
Affiliated companies 95,704 40,083
Accumulated provision for uncollectible accounts (6,237) (4,117)
Refundable income taxes - 17,997
Fossil fuel stock, at average cost 60,615 84,582
Materials and supplies, at average cost 178,299 167,637
Other 52,624 46,011
- ---------------------------------------------------------------------------------------------------------------------------------
Total current assets 1,031,254 848,332
- ---------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 12,431,575 11,783,078
Less accumulated provision for depreciation 5,107,822 4,901,384
- ---------------------------------------------------------------------------------------------------------------------------------
7,323,753 6,881,694
Nuclear fuel, at amortized cost 94,050 106,836
Construction work in progress 744,974 715,153
- ---------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 8,162,777 7,703,683
- ---------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 5) 38,623 34,891
Nuclear decommissioning trusts 313,895 286,653
Other 13,612 12,156
- ---------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 366,130 333,700
- ---------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 7) 345,550 330,405
Prepaid pension costs 268,259 213,971
Debt expense, being amortized 8,758 9,563
Premium on reacquired debt, being amortized 76,020 83,895
Department of Energy assessments 24,588 27,685
Other 95,772 97,470
- ---------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 818,947 762,989
- ---------------------------------------------------------------------------------------------------------------------------------
Total Assets $10,379,108 $9,648,704
=================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-57
BALANCE SHEETS
At December 31, 2000 and 1999
Alabama Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 10) $ 844 $ 100,943
Notes payable 281,343 96,824
Accounts payable --
Affiliated 124,534 91,315
Other 209,205 140,842
Customer deposits 36,814 31,704
Taxes accrued --
Income taxes 65,505 100,569
Other 19,471 18,295
Interest accrued 33,186 26,365
Vacation pay accrued 31,711 30,112
Other 97,743 84,267
- ------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 900,356 721,236
- ------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,425,527 3,190,378
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 1,401,424 1,240,344
Deferred credits related to income taxes (Note 7) 222,485 265,102
Accumulated deferred investment tax credits 249,280 260,367
Employee benefits provisions 84,816 82,298
Prepaid capacity revenues (Note 6) 58,377 79,703
Other 176,559 155,901
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,192,941 2,083,715
- ------------------------------------------------------------------------------------------------------------------------------
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) 3,195,772 2,988,863
- ------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $10,379,108 $9,648,704
==============================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-58
STATEMENTS OF CAPITALIZATION
At December 31, 2000 and 1999
Alabama Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
March 1, 2000 6.00% $ - $ 100,000
2023 through 2024 7.30% - 9.00% 488,991 500,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 488,991 600,000
- ----------------------------------------------------------------------------------------------------------------------------------
Senior notes --
5.35% due November 15, 2003 156,200 156,200
7.850% due May 15, 2003 250,000 -
7.125% due August 15, 2004 250,000 250,000
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 1,202,581 1,207,622
- ----------------------------------------------------------------------------------------------------------------------------------
Total senior notes 2,443,781 2,198,822
- ----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% due 2024 24,400 24,400
Variable rates (4.73% to 5.05% at 1/1/01)
due 2015-2017 89,800 89,800
Non-collateralized:
6.69% due 2021 65,000 -
Variable rates (3.50% to 5.30% at 1/1/01)
due 2021-2028 360,940 425,940
- ----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt (Note 9) 540,140 540,140
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 4,165 5,111
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (50,706) (52,752)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $179.6 million) 3,426,371 3,291,321
Less amount due within one year 844 100,943
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $3,425,527 $3,190,378 46.9% 46.6%
- ----------------------------------------------------------------------------------------------------------------------------------
II-59
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2000 and 1999
Alabama Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
(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 (6.52% at 1/1/01) 50,000 50,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $25.6 million) 347,000 347,000 4.8 5.1
- ----------------------------------------------------------------------------------------------------------------------------------
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 1/1/01
5.14% to 5.25% 70,000 70,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $16.5 million) 317,512 317,512 4.4 4.6
- ----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 6,000,000 shares
Outstanding - 5,608,955 shares in 2000 and 1999
Par value 224,358 224,358
Paid-in capital 1,743,363 1,538,992
Premium on Preferred Stock 99 99
Retained earnings 1,227,952 1,225,414
- ----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 3,195,772 2,988,863 43.9 43.7
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $7,285,811 $6,843,753 100.0% 100.0%
==================================================================================================================================
The accompanying notes are an integral part of these statements.
II-60
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2000, 1999, and 1998
Alabama Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1998 $224,358 $1,304,645 $99 $1,221,467 $2,750,569
Net income after dividends on preferred stock - - - 377,223 377,223
Capital contributions from parent company - 30,000 - - 30,000
Cash dividends on common stock - - - (367,100) (367,100)
Other - - - (6,625) (6,625)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 224,358 1,334,645 99 1,224,965 2,784,067
Net income after dividends on preferred stock - - - 399,880 399,880
Capital contributions from parent company - 204,347 - - 204,347
Cash dividends on common stock - - - (399,600) (399,600)
Other - - - 169 169
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 224,358 1,538,992 99 1,225,414 2,988,863
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
============================================================================================================================
The accompanying notes are an integral part of these statements.
II-61
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2000 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five integrated Southeast utilities, a
system service company (SCS), Southern Communications Services (Southern LINC),
Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern
Nuclear), Mirant Corporation--formerly Southern Energy, Inc.-- and other direct
and indirect subsidiaries. The integrated Southeast utilities --Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company-- provide electric service in four
states. Contracts among the integrated Southeast utilities - related to
jointly-owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS
provides, at cost, specialized services to Southern Company and its subsidiary
companies. Southern LINC provides digital wireless communications services to
the integrated Southeast utilities and also markets these services to the public
within the Southeast. Southern Company Energy Solutions develops new business
opportunities related to energy products and services. Southern Nuclear provides
services to Southern Company's nuclear power plants. Mirant acquires, develops,
builds, owns, and operates power production and delivery facilities and provides
a broad range of energy-related services to utilities and industrial companies
in selected countries around the world. Mirant businesses include independent
power projects, integrated utilities, a distribution company, and energy trading
and marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The Company follows 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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension 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
$187 million, $218 million, and $201 million during 2000, 1999, and 1998,
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 $148 million, $135 million,
and $137 million during 2000, 1999, and 1998, 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 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-62
NOTES (continued)
Alabama Power Company 2000 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:
2000 1999
-----------------------
(in millions)
Deferred income tax charges $ 346 $ 330
Deferred income tax credits (222) (265)
Premium on reacquired debt 76 84
Department of Energy assessments 25 28
Vacation pay 32 30
Natural disaster reserve (18) (19)
Other, net 30 59
- ----------------------------------------------------------------
Total $ 269 $ 247
================================================================
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.
Higher natural gas prices and decreased hydro production combined with increased
costs of purchased power have resulted in a large under-recovery of fuel costs
at December 31, 2000. Effective January 2001, the Company's fuel rate was
increased to address this under-recovery. The Company expects to significantly
reduce this balance over a three-year period.
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 $61
million in 2000, $63 million in 1999, and $59 million in 1998.
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 $25 million at December 31, 2000.
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 2000, 1999 and 1998. 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.
II-63
NOTES (continued)
Alabama Power Company 2000 Annual Report
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.
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 2000 and fund balances as of
December 31, 2000 were:
(in millions)
Amount expensed in 2000 $ 18
----------------------------------------------------------
Accumulated provisions:
External trust funds, at fair value $314
Internal reserves 38
----------------------------------------------------------
Total $352
==========================================================
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 $43 million in 2000,
$23 million in 1999, and $9 million in 1998. The composite rate used to
determine the amount of allowance was 9.6 percent in 2000, 8.8 percent in 1999,
and 9.0 percent in 1998. AFUDC, net of income tax, as a percent of net income
after dividends on preferred stock was 8.4 percent in 2000, 4.7 percent in 1999,
and 1.8 percent in 1998.
II-64
NOTES (continued)
Alabama Power Company 2000 Annual Report
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
The Company uses derivative financial instruments to hedge exposures to
fluctuations in 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 is
unaware of any counterparties that will fail to meet their obligations.
The 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 notional amount is 16 million
euros maturing in 2001 through 2002. At December 31, 2000, the unrecognized gain
on these swaps was approximately $1 million.
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, 2000 $3,422 $3,375
At December 31, 1999 3,286 3,045
Preferred Securities:
At December 31, 2000 347 344
At December 31, 1999 347 299
--------------------------------------------------------------
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, 2000, the reserve
balance was $18 million.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, pension plans that cover
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all employees may become
eligible for such benefits when they retire. The Company funds trusts to the
II-65
NOTES (continued)
Alabama Power Company 2000 Annual Report
extent deductible under federal income tax regulations or to the extent required
by the APSC and 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. The effects of these changes will be to increase annual pension
and postretirement benefits cost by approximately $8 million and $12 million,
respectively.
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:
2000 1999
- ------------------------------------------------------------
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
---------------------------
2000 1999
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $873 $868
Service cost 22 23
Interest cost 64 57
Benefits paid (51) (51)
Actuarial gain and
employee transfers (8) (24)
- ---------------------------------------------------------------
Balance at end of year $900 $873
===============================================================
Plan Assets
---------------------------
2000 1999
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,647 $1,461
Actual return on plan assets 302 245
Benefits paid (51) (51)
Employee transfers 23 (8)
- ---------------------------------------------------------------
Balance at end of year $1,921 $1,647
===============================================================
The accrued pension costs recognized in the Balance Sheets were as
follows:
2000 1999
- ---------------------------------------------------------------
(in millions)
Funded status $1,021 $ 774
Unrecognized transition obligation (21) (25)
Unrecognized prior service cost 33 36
Unrecognized net actuarial gain (765) (571)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 268 $ 214
===============================================================
Components of the pension plans' net periodic cost were as follows:
2000 1999 1998
- ------------------------------------------------------------------
(in millions)
Service cost $ 23 $ 23 $ 22
Interest cost 64 57 59
Expected return on plan assets (119) (109) (102)
Recognized net actuarial gain (20) (14) (16)
Net amortization (2) (2) (2)
- ------------------------------------------------------------------
Net pension income $(54) $ (45) $(39)
==================================================================
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
---------------------------
2000 1999
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $264 $278
Service cost 4 5
Interest cost 19 18
Benefits paid (12) (10)
Actuarial gain and
employee transfers (11) (27)
- ---------------------------------------------------------------
Balance at end of year $264 $264
===============================================================
Plan Assets
---------------------------
2000 1999
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $161 $137
Actual return on plan assets 25 18
Employer contributions 18 16
Benefits paid (12) (10)
- ---------------------------------------------------------------
Balance at end of year $192 $161
===============================================================
II-66
NOTES (continued)
Alabama Power Company 2000 Annual Report
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
2000 1999
- ---------------------------------------------------------------
(in millions)
Funded status $(72) $(103)
Unrecognized transition obligation 49 53
Unrecognized net actuarial gain (35) (12)
Fourth quarter contributions 4 8
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(54) $ (54)
===============================================================
Components of the plans' net periodic cost were as follows:
2000 1999 1998
- ---------------------------------------------------------------
(in millions)
Service cost $ 4 $ 5 $ 5
Interest cost 19 18 18
Expected return on plan assets (13) (11) (9)
Net amortization 4 4 4
- ---------------------------------------------------------------
Net postretirement cost $ 14 $ 16 $18
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.29
percent for 2000, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2000 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $15 $14
Service and interest costs 1 1
===============================================================
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 2000, 1999, and 1998 were $11
million, $10 million, and $10 million, respectively.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs totaling $2.6
million, $5.6 million and $19.4 million for the years 2000, 1999 and 1998,
respectively. These costs were deferred and are being amortized in accordance
with regulatory treatment. The unamortized balance of these costs was $1.4
million at December 31, 2000.
3. CONTINGENCIES AND REGULATORY
MATTERS
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action against the Company in the U. S. District Court. The complaint alleges
violations of the prevention of significant deterioration and new source review
provision of the Clean Air Act with respect to coal-fired generating facilities
at the Company's Plants Miller, Barry and Gorgas. The civil action requests
penalties and injunctive relief, including an order requiring the installation
of the best available control technology at the affected units. 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 and granted SCS's motion to dismiss on the grounds that it neither
owned nor operated the generating units involved in the proceedings. On January
12, 2001, the EPA re-filed its claims against the Company in federal district
court in Birmingham, Alabama. The EPA did not include SCS in the new complaint.
The Company believes that it complied with applicable laws and the EPA's
II-67
NOTES (continued)
Alabama Power Company 2000 Annual Report
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. Both increases and decreases have been placed into effect
since the adoption of these rates. The rate adjustment procedures allow a return
on common equity range of 13.0 percent to 14.5 percent and limit increases or
decreases in rates to 4 percent in any calendar year. There is a moratorium on
any periodic retail rate increases (but not decreases) until July 2001.
In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. In April 1997,
the APSC issued an additional order authorizing the Company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the Company. In 1998, the
Company - in accordance with the 1995 rate order - recorded $33 million of
additional amortization of premium on reacquired debt. The Company did not
record any additional amounts in 2000 or 1999.
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 Company's wholesale
generating facilities under construction in Autaugaville, Alabama, all of which
will be delivered 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 in 2003 while the remaining half is
scheduled for delivery in 2004.
The Company's ratemaking procedures will remain in effect until the APSC
votes to modify or discontinue them.
4. FINANCING AND COMMITMENTS
Construction Program
To the extent possible, the Company's construction program is expected to be
financed primarily from internal sources. Short-term debt is often utilized and
the amounts available are discussed below. The Company may issue additional
long-term debt and preferred securities for debt maturities, redeeming
higher-cost securities, and meeting additional capital requirements.
The Company currently estimates property additions to be $735 million in
2001, $891 million in 2002, and $625 million in 2003.
The Company is constructing 1,230 megawatts of wholesale generating
facilities in Autaugaville, Alabama to begin operation in 2003. Half of this
capacity has been certified by the APSC to serve the Company's retail customers
for seven years. The other half of the capacity will be sold into the wholesale
market and will not affect retail rates. During 2001, the Company plans to
transfer these generating facilities to Southern Power Company (SPC), the new
wholesale subsidiary formed by Southern Company. If the Company transfers
wholesale generation assets to SPC as planned, construction expenditures for the
years 2001 through 2003 will be $598 million, $591 million and $583 million,
respectively.
During 2001, the Company expects to complete the replacement of the steam
generators at Plant Farley, as well as the construction of new generating
capacity at Plant Barry. In addition, 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 capital budget is subject to periodic review and revision, and actual
capital costs incurred may vary from estimates because of changes in such
factors as: business conditions; environmental regulations; nuclear plant
II-68
NOTES (continued)
Alabama Power Company 2000 Annual Report
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.
Financing
The ability of the Company to finance its capital budget depends on the amount
of funds generated internally and the funds it can raise by external financing.
The Company 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.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $925 million
(including $418 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$535 million expire at various times during 2001 and $390 million expire in
2004. In certain cases, such lines require payment of a commitment fee based on
the unused portion of the commitment or the maintenance of compensating balances
with the banks. Because the arrangements are based on an average balance, the
Company does not consider any of its cash balances to be restricted as of any
specific date. Moreover, the Company borrows from time to time pursuant to
arrangements with banks for uncommitted lines of credit.
At December 31, 2000, the Company had regulatory approval to have
outstanding up to $750 million of short-term borrowings.
Assets Subject to Lien
The Company's mortgage, as amended and supplemented, securing the first mortgage
bonds issued by the Company, constitutes a direct lien on substantially all of
the Company's fixed property and franchises.
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, 2000 were as
follows:
Year Commitments
- ---- ---------------
(in millions)
2001 $ -
2002 -
2003 16
2004 34
2005 37
2006 and beyond 180
- -----------------------------------------------------------
Total commitments $ 267
===========================================================
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, 2000, were as follows:
Year Commitments
- ---- ---------------
(in millions)
2001 $ 998
2002 841
2003 722
2004 669
2005 525
2006 - 2024 2,287
- -----------------------------------------------------------
Total commitments $6,042
===========================================================
II-69
NOTES (continued)
Alabama Power Company 2000 Annual Report
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $20.9 million in 2000, $17.8
million in 1999, and $5.8 million in 1998. At December 31, 2000, estimated
minimum rental commitments for noncancellable operating leases were as follows:
Year Commitments
- ---- -------------
(in millions)
2001 $ 22.2
2002 21.6
2003 21.2
2004 18.2
2005 15.5
2006 - 2017 44.7
- -----------------------------------------------------------
Total minimum payments $143.4
===========================================================
5. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power Company own equally all of the outstanding capital
stock of Southern Electric Generating Company (SEGCO), which owns electric
generating units with a total rated capacity of 1,020 megawatts, together with
associated transmission facilities. The capacity of these units is sold equally
to the Company and Georgia Power Company under a contract which, in substance,
requires payments sufficient to provide for the operating expenses, taxes,
interest expense and a return on equity, whether or not SEGCO has any capacity
and energy available. The term of the contract extends automatically for
two-year periods, subject to either party's right to cancel upon two year's
notice. The Company's share of expenses totaled $85 million in 2000, $92 million
in 1999 and $74 million in 1998, and is included in "Purchased power from
affiliates" in the Statements of Income.
In addition, the Company has guaranteed unconditionally the obligation of
SEGCO under an installment sale agreement for the purchase of certain pollution
control facilities at SEGCO's generating units, pursuant to which $24.5 million
principal amount of pollution control revenue bonds are outstanding. Georgia
Power Company has agreed to reimburse the Company for the pro rata portion of
such obligation corresponding to its then proportionate ownership of stock of
SEGCO if the Company is called upon to make such payment under its guaranty.
At December 31, 2000, the capitalization of SEGCO consisted of $51 million
of equity and $78 million of long-term debt on which the annual interest
requirement is $5.3 million. SEGCO paid dividends totaling $5.1 million in 2000,
$4.3 million in 1999, and $8.7 million in 1998, of which one-half of each was
paid to the Company. SEGCO's net income was $5.9 million, $5.4 million, and $7.5
million for 2000, 1999 and 1998, respectively.
The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 2000, 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 $100 $ 46
Plant Miller
Units 1 and 2 743 312
----------------------------------------------------------
6. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the other integrated utility subsidiaries of Southern Company
have entered into long-term contractual agreements for the sale of capacity and
energy to certain non-affiliated utilities located outside the system's service
area. These agreements -- expiring at various dates discussed below -- are firm
and pertain to capacity related to specific generating units. Because the energy
is generally sold at cost under these agreements, profitability is primarily
affected by revenues from capacity sales. The Company's capacity revenues
amounted to $127 million in 2000, $122 million in 1999, and $142 million in
1998.
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 1,235 megawatts of capacity are
II-70
NOTES (continued)
Alabama Power Company 2000 Annual Report
scheduled to be sold through 2001. Thereafter, these sales will remain at that
approximate level -- 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. No notices of cancellation have been received.
Alabama Municipal Electric Authority (AMEA)
Capacity Contracts
In August 1986, the Company entered into a firm power sales contract with AMEA
entitling AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for
a period of 15 years commencing September 1, 1986 (1986 Contract). In October
1991, the Company entered into a second firm power sales contract with AMEA
entitling AMEA to scheduled amounts of additional capacity (to a maximum 80
megawatts) for a period of 15 years commencing October 1, 1991 (1991 Contract).
In both contracts the power will be sold to AMEA for its member municipalities
that previously were served directly by the Company as wholesale customers.
Under the terms of the contracts, the Company received payments from AMEA
representing the net present value of the revenues associated with the
respective capacity entitlements, discounted at effective annual rates of 9.96
percent and 11.19 percent for the 1986 and 1991 contracts, respectively. These
payments are being recognized as operating revenues and the discounts are being
amortized to other interest expense as scheduled capacity is made available over
the terms of the contracts.
In order to secure AMEA's advance payments and the Company's performance
obligation under the contracts, the Company issued and delivered to an escrow
agent first mortgage bonds representing the maximum amount of liquidated damages
payable by the Company in the event of a default under the contracts. No
principal or interest is payable on such bonds unless and until a default by the
Company occurs. As the liquidated damages decline under the contracts, a portion
of the bonds equal to the decreases is returned to the Company. At December 31,
2000, $61.3 million of such bonds were held by the escrow agent under the
contracts.
7. INCOME TAXES
At December 31, 2000, the tax-related regulatory assets and liabilities were
$346 million and $222 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:
2000 1999 1998
--------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $168 $194 $123
Deferred 60 24 72
- -----------------------------------------------------------------
228 218 195
- -----------------------------------------------------------------
State --
Current 27 19 16
Deferred 7 5 7
- ------------------------------------------------------ ----------
34 24 23
- -----------------------------------------------------------------
Total $262 $242 $218
=================================================================
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:
2000 1999
------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 992 $884
Property basis differences 405 419
Fuel cost adjustment 93 65
Premium on reacquired debt 30 31
Pensions 75 60
Other 12 11
- -----------------------------------------------------------------
Total 1,607 1,470
- -----------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 18 24
Other deferred costs 14 25
Postretirement benefits 24 22
Unbilled revenue 23 13
Other 81 63
- -----------------------------------------------------------------
Total 160 147
- -----------------------------------------------------------------
Net deferred tax liabilities 1,447 1,323
Portion included in current liabilities, net (46) (83)
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,401 $1,240
=================================================================
II-71
NOTES (continued)
Alabama Power Company 2000 Annual Report
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 2000, 1999, and 1998. At December 31, 2000, 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:
2000 1999 1998
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.1 2.4 2.5
Non-deductible book
depreciation 1.4 1.6 1.5
Differences in prior years'
deferred and current tax rates (1.3) (1.3) (1.6)
Other (0.7) (0.9) (1.6)
- ---------------------------------------------------------------
Effective income tax rate 37.5% 36.8% 35.8%
===============================================================
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.
8. COMPANY OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES
Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:
Date of Maturity
Issue Amount Rate Notes Date
---------------------------------------------------
(millions) (millions)
Trust I 1/1996 $ 97 7.375% $100 3/2026
Trust II 1/1997 200 7.60 206 12/2036
Trust III 2/1999 50 Auction 52 2/2029
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above. The distribution rate of Trust III's auction rate securities was 6.52% at
January 1, 2001.
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.
9. OTHER LONG-TERM DEBT
Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. The Company is required to make payments sufficient for the
authorities to meet principal and interest requirements of such bonds. With
respect to $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 May 2000, the Company issued $250 million of unsecured senior notes. The
proceeds of this issuance were used to repay short-term indebtedness. All of the
Company's senior notes are, in effect, subordinated to all secured debt of the
Company, including its first mortgage bonds.
The estimated aggregate annual maturities of capitalized lease obligations
through 2005 are as follows: $0.8 million in 2001, $0.9 million in 2002, $0.9
million in 2003, $1.0 million in 2004 and $0.1 million in 2005.
10. 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:
2000 1999
------------------------
(in thousands)
First mortgage bond maturities
and redemptions $ - $100,000
Other long-term debt maturities
(Note 9) 844 943
-------------------------------------------------------------
Total long-term debt due within
one year $844 $100,943
=============================================================
The annual first mortgage bond improvement fund requirement is 1 percent
of the aggregate principal amount of bonds of each series authenticated, so long
II-72
NOTES (continued)
Alabama Power Company 2000 Annual Report
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.
11. 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 private insurance, with the
remaining coverage provided by a mandatory program of deferred premiums which
could be assessed, after a nuclear incident, against all owners of nuclear
reactors. The Company could be assessed up to $88 million per incident for each
licensed reactor it operates but not more than an aggregate of $10 million per
incident to be paid in a calendar year for each reactor. Such maximum
assessment, excluding any applicable state premium taxes, for the Company is
$176 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional cost that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can be insured against increased costs of replacement power in an
amount up to $3.5 million per week (starting 12 weeks after the outage) for one
year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $17 million.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies shall be
dedicated first for the sole purpose of placing the reactor in a safe and stable
condition after an accident. Any remaining proceeds are to be applied next
toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the Company or
to its bond trustees as may be appropriate under the policies and applicable
trust indentures.
All retrospective assessments, whether generated for liability, property or
replacement power may be subject to applicable state premium taxes.
12. COMMON STOCK DIVIDEND
RESTRICTIONS
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 2000, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.
13. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 2000 and 1999 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- -------------------- -----------------------------------------
(in millions)
March 2000 $ 746 $172 $ 68
June 2000 900 229 103
September 2000 1,137 390 209
December 2000 884 151 40
March 1999 $ 714 $162 $ 63
June 1999 823 209 93
September 1999 1,116 388 201
December 1999 733 136 43
- -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-73
SELECTED FINANCIAL AND OPERATING DATA 1996-2000
Alabama Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,667,461 $3,385,474 $3,386,373 $3,149,111 $3,120,775
Net Income after Dividends
on Preferred Stock (in thousands) $419,916 $399,880 $377,223 $375,939 $371,490
Cash Dividends
on Common Stock (in thousands) $417,100 $399,600 $367,100 $339,600 $347,500
Return on Average Common Equity (percent) 13.58 13.85 13.63 13.76 13.75
Total Assets (in thousands) $10,379,108 $9,648,704 $9,225,698 $8,812,867 $8,733,846
Gross Property Additions (in thousands) $870,581 $809,044 $610,132 $451,167 $425,024
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,195,772 $2,988,863 $2,784,067 $2,750,569 $2,714,277
Preferred stock 317,512 317,512 317,512 255,512 340,400
Company obligated mandatorily
redeemable preferred securities 347,000 347,000 297,000 297,000 97,000
Long-term debt 3,425,527 3,190,378 2,646,566 2,473,202 2,354,006
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,285,811 $6,843,753 $6,045,145 $5,776,283 $5,505,683
================================================================================================================================-
Capitalization Ratios (percent):
Common stock equity 43.9 43.7 46.1 47.6 49.3
Preferred stock 4.4 4.6 5.3 4.4 6.2
Company obligated mandatorily
redeemable preferred securities 4.8 5.1 4.9 5.2 1.7
Long-term debt 46.9 46.6 43.7 42.8 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 AA-* AA- AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's BBB+ A- A A A
Fitch A* A A A+ A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 -
Standard and Poor's A A A A -
Fitch A+* A+ A+ A+ -
================================================================================================================================-
Customers (year-end):
Residential 1,132,410 1,120,574 1,106,217 1,092,161 1,073,559
Commercial 193,106 188,368 182,738 177,362 171,827
Industrial 4,819 4,897 5,020 5,076 5,100
Other 745 735 733 728 732
- ---------------------------------------------------------------------------------------------------------------------------------
Total 1,331,080 1,314,574 1,294,708 1,275,327 1,251,218
================================================================================================================================-
Employees (year-end): 6,871 6,792 6,631 6,531 6,865
- ---------------------------------------------------------------------------------------------------------------------------------
*Effective 1/22/01 the Fitch Security Ratings for First Mortgage Bonds, Preferred Stock, and
Unsecured Long-Term Debt are A+, A-, and A respectively.
II-74
SELECTED FINANCIAL AND OPERATING DATA 1996-2000 (continued)
Alabama Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,222,509 $1,145,646 $ 1,133,435 $ 997,507 $ 998,806
Commercial 854,695 807,098 779,169 724,148 696,453
Industrial 859,668 843,090 853,550 775,591 759,628
Other 15,835 15,283 14,523 13,563 13,729
- -----------------------------------------------------------------------------------------------------------------------------------
Total retail 2,952,707 2,811,117 2,780,677 2,510,809 2,468,616
Sales for resale - non-affiliates 461,730 415,377 448,973 431,023 391,669
Sales for resale - affiliates 166,219 92,439 103,562 161,795 216,620
- -----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,580,656 3,318,933 3,333,212 3,103,627 3,076,905
Other revenues 86,805 66,541 53,161 45,484 43,870
- -----------------------------------------------------------------------------------------------------------------------------------
Total $3,667,461 $3,385,474 $3,386,373 $3,149,111 $3,120,775
==================================================================================================================================-
Kilowatt-Hour Sales (in thousands):
Residential 16,771,821 15,699,081 15,794,543 14,336,408 14,593,761
Commercial 12,988,728 12,314,085 11,904,509 11,330,312 10,904,476
Industrial 22,101,407 21,942,889 21,585,117 20,727,912 19,999,258
Other 205,827 201,149 196,647 180,389 192,573
- -----------------------------------------------------------------------------------------------------------------------------------
Total retail 52,067,783 50,157,204 49,480,816 46,575,021 45,690,068
Sales for resale - non-affiliates 14,847,533 12,437,599 11,840,910 12,329,480 9,491,237
Sales for resale - affiliates 5,369,474 5,031,781 5,976,099 8,993,326 10,292,066
- -----------------------------------------------------------------------------------------------------------------------------------
Total 72,284,790 67,626,584 67,297,825 67,897,827 65,473,371
==================================================================================================================================-
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.29 7.30 7.18 6.96 6.84
Commercial 6.58 6.55 6.55 6.39 6.39
Industrial 3.89 3.84 3.95 3.74 3.80
Total retail 5.67 5.60 5.62 5.39 5.40
Sales for resale 3.11 2.91 3.10 2.78 3.07
Total sales 4.95 4.91 4.95 4.57 4.70
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,875 14,097 14,370 13,254 13,705
Residential Average Annual
Revenue Per Customer $1,084.26 $1,028.76 $1,031.21 $922.21 $937.95
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 12,122 11,379 11,151 11,151 11,151
Maximum Peak-Hour Demand (megawatts):
Winter 9,478 8,863 7,757 8,478 8,413
Summer 11,019 10,739 10,329 9,778 9,912
Annual Load Factor (percent) 59.3 59.7 62.9 62.7 61.3
Plant Availability (percent):
Fossil-steam 89.4 80.4 85.6 86.3 86.6
Nuclear 88.3 91.0 80.2 88.8 90.5
- -----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.0 64.1 65.3 65.7 67.0
Nuclear 16.9 17.8 16.3 17.9 18.5
Hydro 2.9 4.7 6.9 7.5 7.1
Oil and gas 4.9 1.1 1.5 0.7 0.4
Purchased power -
From non-affiliates 4.6 4.5 3.3 2.4 2.4
From affiliates 7.7 7.8 6.7 5.8 4.6
- -----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==================================================================================================================================-
II-75
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-76
MANAGEMENT'S REPORT
Georgia Power Company 2000 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
Thomas A. Fanning
Executive Vice President,
Treasurer and Chief
Financial Officer
II-77
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, 2000 and 1999, 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, 2000. 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-88 through II-108)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 2000 and 1999, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 28, 2001
II-78
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 2000 earnings totaled $559 million, representing an $18
million (3.3 percent) increase over 1999. This earnings increase is 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. Georgia Power Company's 1999 earnings
totaled $541 million, representing a $29 million (5.1 percent) decrease from
1998. This earnings decrease was primarily due to the recognition of interest
income in 1998 as a result of the resolution of tax issues with the Internal
Revenue Service (IRS). Earnings in 1999 from normal operations increased due
primarily to lower accelerated depreciation under the GPSC retail rate order,
sales growth, and decreased financing costs, partially offset by retail rate
reductions under the new order and lower wholesale revenues.
Revenues
Operating revenues in 2000 and the amount of change from the prior year are as
follows:
Increase (Decrease)
From Prior Year
Amount ----------------------
2000 2000 1999
---- -----------------------
Retail - (in millions)
Base revenues $3,119 $ 84 $(292)
Fuel cost recovery 1,198 183 44
- ---------------------------------------------------------------------
Total retail 4,317 267 (248)
- ---------------------------------------------------------------------
Sales for resale -
Non-affiliates 298 88 (49)
Affiliates 96 20 (5)
- ---------------------------------------------------------------------
Total sales for resale 394 108 (54)
- ---------------------------------------------------------------------
Other operating revenues 160 39 21
- -------------------------------------------------------- ------------
Total operating revenues $4,871 $414 $(281)
=====================================================================
Percent change 9.3% (5.9)%
- ---------------------------------------------------------------------
Retail base revenues of $3.1 billion in 2000 increased
$84 million (2.8 percent) primarily due to a 4.9 percent increase in sales.
Under the 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. Refunds will be made to customers in 2001. Retail base
revenues of $3.0 billion in 1999 decreased $292 million (8.8 percent) primarily
due to retail rate reductions under the GPSC retail rate order. Pursuant to the
GPSC retail rate order, in 1999 the Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent retail return on
common equity. Revenue subject to refund is reflected in "Base revenues" in the
chart above. The $79 million in refunds were made to customers in 2000. See Note
3 to the financial statements under "Retail Rate Order" 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, 2000, the Company had $132 million in
underrecovered fuel costs. The Company currently plans to make a filing with the
GPSC in early 2001 to establish a new fuel rate in order to better reflect
current fuel cost and to collect the current underrecovered balance.
Wholesale revenues from sales to non-affiliated utilities increased in 2000
and decreased in 1999 as follows:
2000 1999 1998
-------------------------------
(in millions)
Outside service area -
Long-term contracts $ 55 $ 55 $ 51
Other sales 162 74 93
Inside service area 81 81 115
- ---------------------------------------------------------------
Total $298 $210 $259
===============================================================
Revenues from long-term contracts outside the service area remained
constant in 2000 and increased slightly in 1999 due to increased energy sales.
See Note 7 to the financial statements for further information regarding these
sales. Revenues from other sales outside the service area primarily represent
wholesale sales from Plant Dahlberg which went into service during 2000 and
increases in power marketing activities. These activities include the purchase
and resale of energy. Consequently, changes in revenues are generally offset by
corresponding changes in purchased power expense from non-affiliates. Wholesale
II-79
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
revenues from customers within the service area remained constant in 2000 but
decreased in 1999 primarily due to a decrease in revenues under a power supply
agreement with Oglethorpe Power Corporation (OPC).
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 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. In 1999,
other operating revenues increased $21 million or (21 percent) from the
previous year due primarily to increased revenues from the rental of electric
equipment and property.
Kilowatt-hour (KWH) sales for 2000 and the percent change by year were as
follows:
Percent Change
----------------------
2000
KWH 2000 1999
--------- ------------------------
(in billions)
Residential 20.7 6.6% (0.4)%
Commercial 25.6 8.1 3.7
Industrial 27.5 0.9 0.1
Other 0.6 3.2 1.5
---------
Total retail 74.4 4.9 1.1
---------
Sales for resale -
Non-affiliates 6.5 27.7 (21.4)
Affiliates 2.4 35.6 (11.9)
---------
Total sales for resale 8.9 29.8 (19.1)
---------
Total sales 83.3 7.1 (1.0)
=========
- ------------------------------------------------------------
Residential and commercial sales increased 6.6 percent and 8.1 percent,
respectively, 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. In 1999, residential sales
decreased 0.4 percent due to moderate summer temperatures, while commercial
sales increased 3.7 percent due to strong regional economic growth. 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:
2000 1999 1998
-----------------------------
Total generation
(billions of KWH) 73.6 69.3 69.1
Sources of generation
(percent) --
Coal 75.8 75.5 73.3
Nuclear 21.2 21.6 21.6
Hydro 0.8 1.0 2.6
Oil and gas 2.2 1.9 2.5
Average cost of fuel per net
KWH generated
(cents) -- 1.39 1.34 1.36
- -----------------------------------------------------------------
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. Fuel expense increased 0.3 percent in
1999 due to a slight increase in fossil and nuclear generation and a decrease in
generation from hydro plants, partially offset by a lower average cost of fuel.
Purchased power expense in 2000 increased $206 million (53 percent) over
the prior year due to higher retail energy demands and power marketing
activities. The majority of the increase was offset by increases in retail fuel
revenues and power marketing revenues and therefore did not affect earnings. As
discussed above, the expense associated with energy purchased for power
marketing activities is generally offset by revenue when resold. Purchased power
expense decreased slightly in 1999.
Other operation and maintenance expenses in 2000 increased slightly over
those in 1999. Increased line maintenance, customer assistance and sales expense
and additional severance costs were partially offset by decreased generating
plant maintenance and decreased employee benefit provisions. Other operation and
II-80
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
maintenance expenses increased 1.6 percent in 1999 primarily due to increased
generating plant maintenance, partially offset by a reduction in the charges
related to the implementation of a customer service system in 1998, decreased
year 2000 readiness costs, and decreased employee benefit provisions.
Depreciation and amortization increased $66 million in 2000 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. Depreciation and amortization decreased $261 million in 1999 primarily
due to higher depreciation charges recognized in 1998 under the prior GPSC
accounting order and the completion in 1998 of the amortization of deferred
Plant Vogtle costs.
Interest income decreased $3 million in 2000 primarily due to decreased
interest on temporary cash investments. Interest income decreased in 1999
primarily due to the 1998 recognition of $73 million in interest income
resulting from the resolution of tax issues with the IRS and the State of
Georgia. Other, net decreased in 2000 due to an increase in charitable
contributions. In 1999, other, net decreased due primarily to increased bad debt
expense related to consumer energy efficiency improvement financing.
Interest expense, net increased in 2000 due to the issuance of an
additional $300 million in senior notes during 2000. Interest expense, net
decreased in 1999 due primarily to the refinancing or retirement of securities.
The Company refinanced or retired $179 million and $775 million of securities in
2000 and 1999, respectively. Distributions on preferred securities of subsidiary
companies decreased $7 million in 2000 due to the redemption of $100 million of
preferred securities in December 1999. Distributions on preferred securities of
subsidiary companies increased $11 million in 1999 due to the issuance of
additional mandatorily redeemable preferred securities in January 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 life. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
FUTURE EARNINGS POTENTIAL
The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including regulatory matters and energy sales.
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 January 1, 1999, the Company began operating under a new three-year
retail rate order. The Company's earnings are evaluated against a retail return
on common equity range of 10 percent to 12.5 percent, with required rate
reductions of $262 million on an annual basis effective in 1999 and an
additional $24 million effective in 2000. The order provides 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 will be applied to rate reductions, with the remaining one-third
retained by the Company. Pursuant to the GPSC retail rate order, in 2000 and
1999, the Company recorded $85 million in accelerated amortization of regulatory
assets. In 2000, the Company also recorded the additional $50 million of
accelerated amortization. The accelerated amortization is recorded in a
regulatory liability account as mandated by the GPSC. In addition, the Company
recorded $44 million and $79 million of revenue subject to refund for estimated
earnings above 12.5 percent in 2000 and 1999, respectively. Refunds applicable
to 1999 were made to customers in 2000. The Company will file a general rate
case on July 2, 2001 in response to which the GPSC would be expected to
II-81
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
determine whether the retail rate order should be continued, modified, or
discontinued. See Note 3 to the financial statements under "Retail Rate Order"
for additional information.
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. Assuming normal weather,
retail sales growth from 2000 is projected to be approximately 2.4 percent
annually on average during 2001 through 2003.
The Company has entered into purchase power agreements which will result in
higher capacity and operating and maintenance payments in future years. See Note
4 to the financial statements under "Purchased Power Commitments" for additional
information.
The Company is constructing two 566 megawatt combined cycle units at Plant
Wansley to begin operation in 2002. These units have been certified by the GPSC
to serve the Company's retail customers for approximately seven years. Savannah
Electric will have the rights to 200 megawatts of capacity from these units for
the same seven-year period.
The Company is also constructing a 571 megawatt combined cycle unit at
Plant Goat Rock to begin operation in 2002, and a 610 megawatt combined cycle
unit at Plant Goat Rock to begin operation in 2003. The power from these units
will initially be sold into the wholesale market when they begin operation. The
Company has filed with the GPSC for certification of these units to begin
serving the Company's retail customers in 2003 and 2004, respectively, for a
term of seven years each.
In addition to seeking certification of Plant Goat Rock, the Company is
also seeking certification of a seven year commitment to 615 megawatts beginning
in 2004 at Plant Autaugaville to serve its retail customers. Plant Autaugaville
is currently under construction by Alabama Power.
Further, the Company is constructing Plant Dahlberg, a ten unit, 800
megawatt combustion turbine peaking power plant that will serve the wholesale
market. Units one through eight began operation in May 2000; units nine and ten
are expected to begin operation in June 2001. The Company has entered into
wholesale contracts to sell all 800 megawatts of capacity. These contracts cover
substantially all of the output of the plant for the first five years. Because
these units are dedicated to the wholesale market, retail rates will not be
affected.
The Company is aggressively working to maintain and expand its share of
wholesale sales in the Southeastern power markets. In January 2001, Southern
Company announced the formation of a new subsidiary, Southern Power Company
(SPC). SPC will own, manage, and finance wholesale generating assets in the
Southeast. Energy from its assets will be marketed to wholesale customers under
the Southern Company name. The current plan is for Georgia Power and Alabama
Power to transfer Plant Dahlberg and the units under construction at Plants
Wansley, Goat Rock, and Autaugaville to SPC in 2001. The Company will enter into
purchased power capacity agreements with SPC for power from the units at Plants
Wansley, Goat Rock, and Autaugaville to serve the Company's retail customers.
In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income
of approximately $59 million in 2000. Pension plan income in 2001 is expected to
be less as a result of plan amendments. Future pension income is dependent on
several factors including trust earnings and changes to the plan. For additional
information see Note 2 to the financial statements.
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.
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. Although the Energy Act
II-82
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
does not permit retail customer access, it was a major catalyst for the current
restructuring and consolidation taking place within the utility industry.
On December 20, 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. After participating in regional conferences with customers and other
members of the public to discuss the formation of RTOs, utilities were required
to make a filing with the FERC. On October 16, 2000, Southern Company and its
five integrated Southeast utilities, including the Company, filed with the FERC
a proposal for the creation of an RTO. The proposal is for the formation of a
for-profit company that would have control of the bulk power transmission system
of participating utilities. Participants would have the option to either
maintain their ownership, divest, sell, or lease their assets to the proposed
RTO. If the FERC accepts the proposal as filed, the creation of the RTO is not
expected to have a material impact on the financial statements of the Company.
However, the ultimate outcome of this matter cannot now be determined.
The Company continues to 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. Numerous federal and state
initiatives are in varying stages to promote wholesale and retail competition
across the nation. 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. 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
transmission pricing and recovery of costs. The GPSC continues its assessment of
the range of potential stranded costs. The inability of the Company to recover
all its costs, including the regulatory assets described in Note 1 to the
financial statements, could have a material effect on the financial condition of
the Company. The Company is attempting to reduce regulatory assets through the
GPSC retail rate order. See Note 3 to the financial statements under "Retail
Rate Order" for additional information.
The Company is subject to the provisions of FASB Statement No. 71,
Accounting for the Effects of Certain Types of Regulation. In the event that a
portion of the Company's operations is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
The staff of the Securities and Exchange Commission (SEC) has questioned
certain of the current accounting practices of the electric utility industry -
including the Company's - regarding the recognition, measurement, and
classification in the financial statements of decommissioning costs for nuclear
generating facilities. In response to these questions, the FASB is reviewing the
accounting for liabilities related to the retirement of long-lived assets,
including nuclear decommissioning. If the FASB issues new accounting rules, the
estimated costs of retiring the Company's nuclear and other facilities may be
required to be recorded as liabilities in the Balance Sheets. Also, the annual
provisions for such costs could change. Because of the Company's current ability
to recover asset retirement costs through rates, these changes would not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.
Exposure to Market Risks
Due to cost-based rate regulation, the Company currently has limited exposure to
market volatility in interest rates, commodity fuel prices and prices of
electricity. (See the discussion above for potential changes in industry
structure.) 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, 2000,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Also, based on the Company's
overall interest rate exposure at December 31, 2000, a near-term 100 basis point
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
change in interest rates would not materially affect the financial statements.
New Accounting Standard
In June 2000, the FASB issued Statement No. 138, an amendment of Statement
No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement
No. 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. Statement No. 133 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.
Substantially all of the Company's bulk energy purchases and sales meet the
definition of a derivative under Statement No. 133. In many cases, these
transactions meet the normal purchase and sale exception and the related
contracts will continue to be accounted for under the accrual method. Certain of
these instruments qualify as cash flow hedges resulting in the deferral of
related gains and losses in other comprehensive income until the hedged
transactions occur. Any ineffectiveness will be recognized currently in net
income. However, others will be required to be marked to market through current
period income.
The Company adopted the provisions of Statement No. 133 effective January
1, 2001. The impact on net income was immaterial. The application of the new
rules is still evolving and further guidance from the FASB is expected, which
could additionally impact the Company's financial statements.
FINANCIAL CONDITION
Plant Additions
In 2000, gross utility plant additions were $1.1 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.
Financing Activities
In 2000, the Company's financing costs increased due to the issuance of new debt
during the year. New issues during 1998 through 2000 totaled $1.5 billion and
retirement or repayment of higher-cost securities totaled $1.7 billion.
Special purpose subsidiaries of the Company have issued mandatorily
redeemable preferred securities. See Note 9 to the financial statements under
"Preferred Securities" for additional information.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 1998 through 2000, as of year-end, were as
follows:
2000 1999 1998
----------------------------------
Composite interest rate
on long-term debt 5.90% 5.48% 5.64%
Composite preferred
stock dividend rate 4.60 4.60 5.52
Composite preferred
securities dividend rate 7.49 7.49 7.89
- ------------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations decreased by $135 million in 2000, primarily due
to higher fuel and purchased power expenses related to increased energy demands.
The Company estimates that construction expenditures for the years 2001
through 2003 will total $1.6 billion, $1.3 billion, and $0.8 billion,
respectively. If the Company transfers wholesale generation assets to SPC in
2001 as contemplated, construction expenditures for the years 2001 through 2003
will total $1.0 billion, $0.9 billion, and $0.7 billion, respectively.
Investments in additional combustion turbine and combined cycle generating
units, transmission and distribution facilities, enhancements to existing
generating plants, and equipment to comply with environmental requirements are
planned.
Cash requirements for redemptions announced and maturities of long-term
debt are expected to total $581 million during 2001 through 2003.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
II-84
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
decommissioning costs. The amount to be funded is $30 million each year in 2001,
2002, and 2003. 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, if needed,
by the issuance of new debt and equity securities, term loans, and short-term
borrowings. 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 2001. See Note 9 to the financial statements under "Bank Credit
Arrangements" for additional information.
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 the later securities has been steadily
declining during the last four years.
If the Company were to choose to issue new first mortgage bonds or
preferred stock once again, it would be required to meet certain coverage
requirements.
ENVIRONMENTAL ISSUES
Clean Air Act
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. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and some 50 generating units within Southern
Company's subsidiaries were brought into compliance with Phase I requirements.
Southern Company's subsidiaries, including the Company, achieved Phase I
sulfur dioxide compliance at the affected units by switching to low-sulfur coal,
which required 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.
The one-hour ozone non-attainment standards for the Atlanta area have been
set and must be implemented in May 2003. Seven generating plants will be
affected in the Atlanta area. Additional construction expenditures for the
Company's compliance with these new rules are currently estimated at
approximately $705 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.
II-85
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
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 equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. The Company believes that it complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly financial
condition unless such costs can be recovered through regulated rates.
Other Environmental Issues
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 recently dismissed certain challenges but 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
will address other legal challenges to these standards in mid-2001. If the
standards are eventually upheld, implementation could be required by 2007 to
2010.
In September 1998, the EPA issued the final regional nitrogen oxide
reduction rules to the states for implementation. Compliance is required by May
31, 2004. The final rule affects 21 states, including Georgia.
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 (MACT) provisions of the Clean Air Act. This determination is being
challenged in the courts. 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 would likely
be required around 2010. Litigation of the BART rules is probable in the near
future.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C.
add to the uncertainties associated with BART guidance and the MACT
determination for mercury and other HAPS.
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 costs and has recognized in the financial statements costs to
clean up known sites. These costs for the Company amounted to $4 million, $4
million, and $6 million in 2000, 1999, and 1998, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion of or all 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 a site in Brunswick,
Georgia, and the status of sites listed on the State of Georgia's hazardous site
inventory.
II-86
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2000 Annual Report
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; water intake
restrictions; and hazardous waste disposal requirements. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
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.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
The Company's 2000 Annual Report contains forward-looking and historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "expects," "plans," "anticipates,"
"believes," "estimates," "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 and the race
discrimination litigation against the Company; the extent and timing of the
entry of additional competition in the Company's markets; potential business
strategies, including acquisitions or dispositions of assets or businesses,
which cannot be assured to be completed or beneficial; internal restructuring or
other restructuring options, that may be pursued by the Company; state and
federal rate regulation in the United States; political, legal and economic
conditions and developments in the United States; financial market conditions
and the results of financing efforts; the impact of fluctuations in commodity
prices, interest rates and customer demand; 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
SEC.
II-87
STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Georgia Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $4,317,338 $4,050,088 $4,298,217
Sales for resale --
Non-affiliates 297,643 210,104 259,234
Affiliates 96,150 76,426 81,606
Other revenues 159,487 120,057 99,196
- ------------------------------------------------------------------------------------------------------------
Total operating revenues 4,870,618 4,456,675 4,738,253
- ------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 1,017,878 919,876 917,119
Purchased power --
Non-affiliates 356,189 214,573 229,960
Affiliates 239,815 174,989 161,003
Other 795,458 784,359 819,589
Maintenance 404,189 411,983 358,218
Depreciation and amortization 619,094 552,966 813,802
Taxes other than income taxes 204,527 202,853 204,623
Write down of Rocky Mountain plant - - 33,536
- ------------------------------------------------------------------------------------------------------------
Total operating expenses 3,637,150 3,261,599 3,537,850
- ------------------------------------------------------------------------------------------------------------
Operating Income 1,233,468 1,195,076 1,200,403
Other Income (Expense):
Interest income 2,629 5,583 79,578
Equity in earnings of unconsolidated subsidiaries 3,051 2,721 3,735
Other, net (50,495) (47,986) (38,277)
- ------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 1,188,653 1,155,394 1,245,439
- ------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest expense, net 208,868 194,869 216,313
Distributions on preferred securities of subsidiaries 59,104 65,774 54,327
- ------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 267,972 260,643 270,640
- ------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 920,681 894,751 974,799
Income taxes 360,587 351,639 398,632
- ------------------------------------------------------------------------------------------------------------
Net Income 560,094 543,112 576,167
Dividends on Preferred Stock 674 1,729 5,939
- ------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 559,420 $ 541,383 $ 570,228
============================================================================================================
The accompanying notes are an integral part of these statements.
II-88
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
Georgia Power Company 2000 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 560,094 $ 543,112 $ 576,167
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 712,960 663,878 867,637
Deferred income taxes and investment tax credits, net (28,961) (34,930) (93,005)
Other, net (51,501) (42,179) 40,396
Changes in certain current assets and liabilities --
Receivables, net (108,621) 21,665 (25,453)
Fossil fuel stock 26,835 (22,165) (8,066)
Materials and supplies (9,715) (10,417) (3,090)
Accounts payables 64,412 13,095 47,862
Energy cost recovery, retail (95,235) (26,862) (7,649)
Other (9,092) 90,788 6,997
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,061,176 1,195,985 1,401,796
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,078,163) (790,464) (499,053)
Other (5,450) (27,454) 67,031
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (1,083,613) (817,918) (432,022)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 67,598 295,389 (25,378)
Proceeds --
Senior notes 300,000 100,000 495,000
Pollution control bonds 78,725 238,000 89,990
Preferred securities - 200,000 -
Capital contributions from parent company 301,514 155,777 235
Retirements --
First mortgage bonds (100,000) (404,000) (558,250)
Pollution control bonds (78,725) (235,000) (89,990)
Preferred securities - (100,000) -
Preferred stock (383) (36,231) (106,064)
Capital distributions to parent company - - (270,000)
Payment of preferred stock dividends (751) (984) (9,137)
Payment of common stock dividends (549,600) (543,000) (536,600)
Other (1,231) (29,630) (26,641)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 17,147 (359,679) (1,036,835)
- -------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (5,290) 18,388 (67,061)
Cash and Cash Equivalents at Beginning of Year 34,660 16,272 83,333
- -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $29,370 $34,660 $16,272
- -------------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 265,373 $ 247,050 $ 269,524
Income taxes (net of refunds) 392,310 394,457 480,318
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-89
BALANCE SHEETS
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
Assets 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 29,370 $ 34,660
Receivables --
Customer accounts receivable 465,249 401,773
Unrecovered retail fuel clause revenue 131,623 36,388
Other accounts and notes receivable 156,143 102,544
Affiliated companies 13,312 16,006
Accumulated provision for uncollectible accounts (5,100) (7,000)
Fossil fuel stock, at average cost 99,463 126,298
Materials and supplies, at average cost 263,609 253,894
Other 97,515 63,990
- ------------------------------------------------------------------------------------------------------------------------------------
Total current assets 1,251,184 1,028,553
- ------------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 16,469,706 15,798,624
Less accumulated provision for depreciation 6,914,512 6,538,574
- ------------------------------------------------------------------------------------------------------------------------------------
9,555,194 9,260,050
Nuclear fuel, at amortized cost 120,570 119,288
Construction work in progress (Note 4) 652,264 425,975
- ------------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 10,328,028 9,805,313
- ------------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4) 25,485 25,024
Nuclear decommissioning trusts 375,666 371,914
Other 33,829 33,766
- ------------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 434,980 430,704
- ------------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 565,982 590,893
Prepaid pension costs 205,113 145,801
Debt expense, being amortized 53,748 55,824
Premium on reacquired debt, being amortized 173,610 184,331
Other 120,964 120,441
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,119,417 1,097,290
- ------------------------------------------------------------------------------------------------------------------------------------
Total Assets $13,133,609 $12,361,860
====================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-90
BALANCE SHEETS
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2000 1999
- ---------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 9) $ 1,808 $ 155,772
Notes payable 703,839 636,241
Accounts payable --
Affiliated 117,168 76,591
Other 397,550 346,785
Customer deposits 78,540 74,695
Taxes accrued --
Income taxes 5,151 7,914
Other 137,511 127,414
Interest accrued 47,244 58,665
Vacation pay accrued 38,865 38,143
Other 153,400 153,767
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 1,681,076 1,675,987
- ---------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,041,939 2,688,358
- ---------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,182,783 2,202,565
Deferred credits related to income taxes (Note 8) 247,067 267,083
Accumulated deferred investment tax credits (Note 8) 352,282 367,114
Employee benefits provisions 177,444 181,529
Other 397,655 236,812
- ---------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,357,231 3,255,103
- ---------------------------------------------------------------------------------------------------------------
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 14,952
- ---------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 4,249,544 3,938,210
- ---------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $13,133,609 $12,361,860
===============================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-91
STATEMENTS OF CAPITALIZATION
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
March 1, 2000 6.00% $ - $ 100,000
April 1, 2003 6.625% 200,000 200,000
August 1, 2003 6.35% 75,000 75,000
2005 6.07% 10,000 10,000
2008 6.875% 50,000 50,000
2025 7.70% 57,000 57,000
- ----------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 392,000 492,000
- ----------------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
Variable rate (6.71375% at 1/1/01) due February 22, 2002 300,000 -
5.50% due December 1, 2005 150,000 150,000
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 895,000 595,000
- ----------------------------------------------------------------------------------------------------------------
Other long-term debt -- (Note 9)
Pollution control revenue bonds --
Maturity Interest Rates
-------- -------------
2000 4.375% - 50,000
2005 5.00% 57,000 57,000
2011 Variable (5.10% at 1/1/01) 10,450 10,450
2018-2019 6.00% to 6.25% 13,100 13,100
2021-2025 5.40% to 6.75% 308,660 337,385
2022-2025 Variable (4.85% to 5.35% at 1/1/01) 622,075 622,075
2026-2030 Variable (5.00% to 5.10% at 1/1/01) 206,180 206,180
2030 4.53% 78,725 -
2032-2034 Variable (5.0% to 5.30% at 1/1/01) 140,000 140,000
2034 5.25% to 5.45% 238,000 238,000
- ----------------------------------------------------------------------------------------------------------------
Total other long-term debt 1,674,190 1,674,190
- ----------------------------------------------------------------------------------------------------------------
Capital lease obligations (Note 9) 85,179 85,851
- ----------------------------------------------------------------------------------------------------------------
Unamortized debt discount, net (2,622) (2,911)
- ----------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $179.6 million) 3,043,747 2,844,130
Less amount due within one year (Note 9) 1,808 155,772
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year $ 3,041,939 $ 2,688,358 37.6 % 36.2 %
- -----------------------------------------------------------------------------------------------------------------------------------
II-92
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2000 and 1999
Georgia Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
(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 9.7 10.6
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 145,689 shares at December 31, 2000
Outstanding -- 149,520 shares at December 31, 1999
$100 stated value --
4.60% 14,569 14,952
- -----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $0.7 million) 14,569 14,952 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 2,117,497 1,815,983
Premium on preferred stock 40 40
Retained earnings (Note 9) 1,787,757 1,777,937
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statements) 4,249,544 3,938,210 52.5 53.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,095,302 $ 7,430,770 100.0 % 100.0 %
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-93
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2000, 1999, and 1998
Georgia Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1998 $344,250 $1,929,971 $160 $1,745,347 $4,019,728
Net income after dividends on preferred stock - - - 570,228 570,228
Capital distributions to parent company - (270,000) - - (270,000)
Capital contributions from parent company - 235 - - 235
Cash dividends on common stock - - - (536,600) (536,600)
Preferred stock transactions, net - - (2) 583 581
- --------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 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
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-94
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2000 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 integrated Southeast utilities, Southern Company Services
(SCS), the system service company, Southern Communications Services (Southern
LINC), Mirant Corporation (formerly Southern Energy), Southern Nuclear Operating
Company (Southern Nuclear), Southern Company Energy Solutions, and other direct
and indirect subsidiaries. The integrated Southeast utilities (Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company) provide electric service in four
states. Contracts among the integrated Southeast utilities -- related to jointly
owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC). SCS provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the
subsidiary companies and also markets these services to the public within the
Southeast. Southern Company Energy Solutions develops new business opportunities
related to energy products and services. Southern Nuclear provides services to
Southern Company's nuclear power plants. Mirant Corporation acquires, develops,
builds, owns, and operates power production and delivery facilities and provides
a broad range of energy-related services to utilities and industrial companies
in selected countries around the world. Mirant Corporation's businesses include
independent power projects, integrated utilities, a distribution company, and
energy trading and marketing businesses outside the Southeastern United States.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
is also subject to regulation by the FERC and the 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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $269 million, $253
million, and $251 million during 2000, 1999, and 1998, 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, $270 million, and
$269 million during 2000, 1999, and 1998, 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 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. Pursuant to the terms of the GPSC
retail rate order, the Company recorded $135 million and $85 million in 2000 and
1999, respectively, of accelerated cost recovery of regulatory assets which have
II-95
NOTES (continued)
Georgia Power Company 2000 Annual Report
been recorded on the balance sheet as a regulatory liability. See Note 3 under
"Retail Rate Order" for additional information. Regulatory assets and
(liabilities) reflected in the Company's Balance Sheets at December 31 relate to
the following:
2000 1999
----------------------
(in millions)
Deferred income taxes $ 566 $ 591
Deferred income tax credits (247) (267)
Premium on reacquired debt 174 184
Corporate building lease 55 54
Vacation pay 49 47
Postretirement benefits 30 33
Department of Energy assessments 21 24
Deferred nuclear outage costs 28 26
Accelerated cost recovery (220) (85)
Interest, accelerated cost recovery (10) -
Other, net 23 3
- ---------------------------------------------------------------
Total $ 469 $ 610
===============================================================
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.
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.
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.
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 2000, $74 million in 1999, and $74 million in 1998. 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 contracts, and the Company is
pursuing legal remedies against the government for breach of contract. Effective
June 2000, the on-site dry storage facility for Plant Hatch became operational.
Sufficient capacity is believed available to continue dry storage operations at
Plant Hatch through the life of the plant. Sufficient fuel storage capacity
currently is available at Plant Vogtle to maintain full-core discharge
capability for both units into the year 2014.
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, 2000 to be approximately $19 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 2000 and 1999, and 3.2 percent in 1998. In addition, pursuant to
a GPSC retail rate order, the Company recorded accelerated depreciation of
electric plant of $304 million in 1998. Total accelerated depreciation recorded
under the GPSC retail rate order was $467 million. These charges are recorded in
the accumulated provision for depreciation. When property subject to
depreciation is retired or otherwise disposed of in the normal course of
II-96
NOTES (continued)
Georgia Power Company 2000 Annual Report
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
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 a set period of time as ordered by the GPSC. 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. The Company
has filed with the NRC an application requesting a 20-year renewal of the
licenses for both units at Plant Hatch which would permit the operation of both
units until 2034.
Annual provisions for nuclear decommissioning expense are based on an
annuity method as approved by the GPSC. The amounts expensed in 2000 and fund
balances as of December 31, 2000 were:
Plant Plant
Hatch Vogtle
- ----------------------------------------------------------------
(in millions)
Amount expensed in 2000 $ 19 $ 9
================================================================
(in millions)
Accumulated provisions:
External trust funds, at fair value $230 $146
Internal reserves 20 12
- ----------------------------------------------------------------
Total $250 $158
================================================================
Effective January 1, 1999, the GPSC increased the annual provision for
decommissioning expenses to $28 million from $20 million in 1998. This amount
is based on the NRC generic estimate to decommission the radioactive
II-97
NOTES (continued)
Georgia Power Company 2000 Annual Report
portion of the facilities as of 1997 of $526 million and $438 million for
Plants Hatch and Vogtle, respectively. The ultimate costs associated with the
1997 NRC minimum funding requirements are $1.1 billion and $1.3 billion for
Plants Hatch and Vogtle, respectively. Significant assumptions include an
estimated inflation rate of 3.6 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.
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
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 2000, 1999, and 1998, the average AFUDC
rates were 6.74 percent, 5.61 percent, and 6.71 percent, respectively. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 2.0 percent for 2000, 1999 and 1998.
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.
Financial Instruments
The Company has a firm commitment that requires payment in euros. As a hedge
against fluctuations in the exchange rate for euros, the Company entered into
forward currency swaps. The notional amount is 15.9 million euros maturing in
2001 through 2002. At December 31, 2000, the unrecognized gain on these swaps
was approximately $1.3 million.
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, 2000 $2,959 $2,912
At December 31, 1999 $2,758 $2,604
Preferred securities:
At December 31, 2000 $789 $761
At December 31, 1999 $789 $680
- --------------------------------------------------------------
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
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 FERC. In late 2000, the Company
adopted several pension and postretirement benefits plan changes that had the
II-98
NOTES (continued)
Georgia Power Company 2000 Annual Report
effect of increasing benefits to both current and future retirees. The effects
of these changes will be to increase annual pension and postretirement benefits
costs by approximately $10 million and $6 million, respectively. 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:
2000 1999
- -----------------------------------------------------------------
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
---------------------------
2000 1999
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,205 $1,217
Service cost 32 33
Interest cost 88 80
Benefits paid (58) (57)
Actuarial gain and
employee transfers (14) (68)
- ----------------------------------------------------------------
Balance at end of year $1,253 $1,205
================================================================
Plan Assets
---------------------------
2000 1999
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $2,107 $1,859
Actual return on plan assets 385 313
Benefits paid (58) (57)
Employee transfers 30 (8)
- ----------------------------------------------------------------
Balance at end of year $2,464 $2,107
================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999
- ---------------------------------------------------------------
(in millions)
Funded status $ 1,211 $ 902
Unrecognized transition obligation (26) (30)
Unrecognized prior service cost 38 41
Unrecognized net actuarial gain (1,018) (767)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 205 $ 146
===============================================================
Components of the plan's net periodic cost were as follows:
2000 1999 1998
- ---------------------------------------------------------------
(in millions)
Service cost $ 32 $ 33 $ 30
Interest cost 88 80 82
Expected return on plan assets (151) (137) (127)
Recognized net actuarial gain (27) (17) (20)
Net amortization (1) (1) (1)
- ---------------------------------------------------------------
Net pension income $ (59) $ (42) $ (36)
===============================================================
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
---------------------------
2000 1999
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $438 $464
Service cost 7 8
Interest cost 36 30
Benefits paid (21) (19)
Actuarial gain and
employee transfers (28) (45)
Amendments 63 -
- ----------------------------------------------------------------
Balance at end of year $495 $438
================================================================
II-99
NOTES (continued)
Georgia Power Company 2000 Annual Report
Plan Assets
---------------------------
2000 1999
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $177 $150
Actual return on plan assets 12 11
Employer contributions 30 35
Benefits paid (21) (19)
- ----------------------------------------------------------------
Balance at end of year $198 $177
================================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2000 1999
- ---------------------------------------------------------------
(in millions)
Funded status $ (297) $ (261)
Unrecognized transition obligation 113 122
Unrecognized prior service cost 60 -
Unrecognized gain (13) -
Unrecognized net actuarial loss - 10
Fourth quarter contributions 27 14
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (110) $(115)
===============================================================
Components of the plans' net periodic cost were as follows:
2000 1999 1998
- ---------------------------------------------------------------
(in millions)
Service cost $ 7 $ 8 $ 7
Interest cost 36 30 32
Expected return on plan assets (16) (10) (9)
Recognized net actuarial loss - 1 1
Net amortization 12 9 9
- ------------------------------------------------------ --------
Net postretirement cost $ 39 $ 38 $40
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.29
percent for 2000, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2000 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $ 39 $ 34
Service and interest costs 3 3
===============================================================
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 2000, 1999, and 1998 were $15
million, $15 million, and $14 million, respectively.
3. CONTINGENCIES & REGULATORY MATTERS
Retail Rate Order
On December 18, 1998, the GPSC approved a three-year retail rate order for the
Company ending December 31, 2001. Under the terms of the order, earnings are
evaluated against a retail return on common equity range of 10 percent to 12.5
percent. Retail rates were decreased by $262 million on an annual basis
effective January 1, 1999, and by an additional $24 million effective January 1,
2000. The order further provides 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 will
be applied to rate reductions, with the remaining one-third retained by the
Company. Pursuant to the order, in 2000 and 1999, the Company recorded $85
million each year in accelerated amortization of regulatory assets. In 2000, the
Company also recorded the additional $50 million of accelerated amortization.
The accelerated amortization is recorded in a regulatory liability account and,
as mandated by the GPSC, the Company recorded $10 million of interest on the
amounts in the regulatory liability account. In addition, the Company recorded
$44 million and $79 million of revenue subject to refund for estimated earnings
above 12.5 percent retail return on common equity in 2000 and 1999,
respectively. Refunds applicable to 1999 were made to customers in 2000. The
estimated 2000 refund is included in other current liabilities on the Balance
Sheet. The Company will file a general rate case on July 2, 2001, in response to
II-100
NOTES (continued)
Georgia Power Company 2000 Annual Report
which the GPSC would be expected to determine whether the rate order should be
continued, modified, or discontinued.
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 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.
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.
Other Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 2000, the Company
has recognized approximately $5 million in cumulative expenses associated with
the Company's agreed upon share of removal and remedial investigation and
feasibility study costs for this site. The final outcome of this matter cannot
now be determined. However, based on the nature and extent of the Company's
activities relating to the site, management believes that the Company's portion
of any remaining remediation costs should not be material to the financial
statements.
In compliance with the Georgia Hazardous Site Response Act of 1993, the
State of Georgia was required to compile an inventory of all known or suspected
sites where hazardous wastes, constituents, or substances have been disposed of
or released in quantities deemed reportable by the State. In developing this
list, the State identified several hundred properties throughout the State,
including 34 sites which may require environmental remediation that were either
previously or are currently owned by the Company. The majority of these sites
are electrical power substations and power generation facilities. The Company
has remediated ten electrical substations on the list at a cumulative cost of
approximately $3 million through December 31, 2000. The State has removed from
the list three power generation facilities following the assessment which
indicated no remediation was necessary. In addition, the Company has recognized
approximately $27.5 million in cumulative expenses through December 31, 2000 for
the assessment of the remaining sites on the list and the anticipated clean-up
cost for 14 sites that the Company plans to remediate. Any additional costs of
remediating the remaining sites cannot presently be determined until such
studies are completed for each site and the State determines whether remediation
is required. If all listed sites were required to be remediated, the Company
could incur expenses of up to approximately $5 million in additional clean-up
costs and construction expenditures of up to approximately $37 million to
develop new waste management facilities or install additional pollution control
devices.
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
II-101
NOTES (continued)
Georgia Power Company 2000 Annual Report
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.
In January 1997, the GPSC approved a performance award of approximately
$11.7 million for performance during the 1993-1995 period. This award was
collected through the retail fuel cost recovery provision and recognized in
income over the 36-month period ending in December 1999. In February 2000, the
GPSC approved a performance award of approximately $7.8 million for performance
during the 1996-1998 period. This award is being collected through the retail
fuel cost recovery provision and recognized in income over a 36-month period
that began in January 2000, 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 and a new defendant, Southern Company Energy Solutions, Inc. The
lawsuit is in the discovery stage. The final outcome of this case cannot now be
determined.
4. COMMITMENTS
Construction Program
The Company is constructing Plant Dahlberg, a ten unit, 800 megawatt combustion
turbine peaking power plant. Units one through eight began operation in May
2000; units nine and ten are expected to begin operation in June 2001. The
Company is also constructing a 571 megawatt combined cycle unit and a 610
megawatt combined cycle unit at Plant Goat Rock that will begin operation in
2002 and in 2003, respectively, and an addition of two 566 megawatt combined
cycle units at Plant Wansley, to begin operation in 2002. During 2001, the
Company plans to transfer the units at Plants Dahlberg, Goat Rock, and Wansley
at net book value to Southern Power Company (SPC), a new subsidiary formed by
Southern Company. Significant construction of transmission and distribution
facilities, and projects to upgrade and extend the useful life of generating
plants and to remain in compliance with environmental requirements will
continue. The Company currently estimates property additions to be approximately
$1.6 billion in 2001, $1.3 billion in 2002, and $0.8 billion in 2003. If the
Company transfers wholesale generation assets to SPC in 2001 as contemplated,
construction expenditures for the years 2001 through 2003 will total $1.0
billion, $0.9 billion, and $0.7 billion, respectively.
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.
Total estimated long-term fossil and nuclear fuel commitments at December 31,
2000 were as follows:
Minimum
Year Obligations
- ---- -----------------
(in millions)
2001 $1,006
2002 625
2003 586
2004 430
2005 342
2006 and beyond 873
- -------------------------------------------------------------
Total minimum obligations $3,862
=============================================================
Additional commitments for coal and for nuclear fuel will be required in
the future to supply the Company's fuel needs.
Purchased Power Commitments
The Company and an affiliate, Alabama Power Company, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
II-102
NOTES (continued)
Georgia Power Company 2000 Annual Report
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 Company 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:
2000 1999 1998
---------------------------------
(in millions)
Energy $57 $51 $45
Capacity 30 29 30
- --------------------------------------------------------------
Total $87 $80 $75
==============================================================
Kilowatt-hours 3,835 3,338 3,146
- --------------------------------------------------------------
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 $58 million, $57 million, and $56 million in 2000, 1999, and 1998,
respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments
----------------------
(in millions)
2001 $ 59
2002 58
2003 58
2004 55
2005 55
2006 and beyond 539
- ----------------------------------------------------------------
Total capacity payments $ 824
================================================================
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.
The Company has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
2000 were as follows:
Year Other Obligations
----------------------
(in millions)
2001 $ 22
2002 39
2003 41
2004 40
2005 40
2006 and beyond 154
- ----------------------------------------------------------------
Total other obligations $336
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $16 million for 2000, $11 million
for 1999, and $13 million for 1998. At December 31, 2000, estimated minimum
rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations
--------------------------
(in millions)
2001 $ 15
2002 15
2003 15
2004 16
2005 14
2006 and beyond 102
- -----------------------------------------------------------------
Total minimum obligations $ 177
=================================================================
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
private insurance, with the remaining coverage provided by a mandatory program
II-103
NOTES (continued)
Georgia Power Company 2000 Annual Report
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 be insured against increased costs of replacement power in an
amount up to $3.5 million per week -- starting 12 weeks after the outage -- for
one year and up to $2.8 million per week for the second and third years.
Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $19 million.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies 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, 2000, 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% $3,301* $1,724
Plant Hatch (nuclear) 50.1 873 650
Plant Wansley (coal) 53.5 300 150
Plant Scherer (coal)
Units 1 and 2 8.4 112 53
Unit 3 75.0 545 207
Plant McIntosh
Common Facilities 75.0 19 2
(combustion-turbine)
Rocky Mountain 25.4 169* 72
(pumped storage)
Intercession City 33.3 11 1
(combustion-turbine)
- --------------------------------------------------------------------
* Investment net of write-offs.
7. LONG-TERM POWER SALES AND LEASE
AGREEMENTS
The Company and the other integrated Southeast utilities of Southern Company
have long-term contractual agreements for the sale of capacity and energy to
non-affiliated utilities located outside the system's service area. These
II-104
NOTES (continued)
Georgia Power Company 2000 Annual Report
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)
2000 $ 30 124
1999 32 162
1998 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 2000 with a minimum of three years notice until the expiration of
the contracts in 2010.
During 2000, the Company entered into certain operating leases for portions
of its generating unit capacity. Minimum future capacity revenues from
noncancelable operating leases as of December 31, 2000 were as follows:
Year Minimum Obligations
--------------------------
(in millions)
2001 $ 41
2002 45
2003 45
2004 45
2005 5
2006 and beyond -
- -----------------------------------------------------------------
Total minimum obligations $181
=================================================================
8. INCOME TAXES
At December 31, 2000, tax-related regulatory assets were $566 million and
tax-related regulatory liabilities were $247 million. 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 the federal and state income tax provisions are as follows:
2000 1999 1998
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Current $ 342 $333 $415
Deferred (34) (34) (87)
Deferred investment tax
credits - - 7
- -----------------------------------------------------------------
308 299 335
- -----------------------------------------------------------------
State:
Current 48 54 77
Deferred (5) (6) (13)
Deferred investment tax
credits 10 5 -
- -----------------------------------------------------------------
Total $361 $352 $399
=================================================================
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:
2000 1999
------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 1,755 $1,766
Property basis differences 683 729
Other 243 155
- ------------------------------------------------------------------
Total 2,681 2,650
- ------------------------------------------------------------------
Deferred tax assets:
Other property basis differences 189 200
Federal effect of state deferred taxes 91 93
Other deferred costs 208 109
Other 37 48
- ------------------------------------------------------------------
Total 525 450
- ------------------------------------------------------------------
Net deferred tax liabilities 2,156 2,200
Portion included in current assets 27 3
- ------------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $ 2,183 $2,203
==================================================================
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 2000 and 1999, and $22 million in 1998. At December
31, 2000, all investment tax credits available to reduce federal income taxes
payable had been utilized.
II-105
NOTES (continued)
Georgia Power Company 2000 Annual Report
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
2000 1999 1998
--------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 2 6
Other (2) (2) (4)
- ---------------------------------------------------------------
Effective income tax rate 39% 39% 41%
===============================================================
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.
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. At December 31, 2000,
$891 million 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. If additional first mortgage bonds are issued, supplemental
indentures in connection with those issues may contain more stringent
restrictions than those currently in effect. 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
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 $378.8 million of its
first mortgage bonds outstanding at December 31, 2000, which are pledged as
security for its obligations under pollution control revenue contracts. No
interest on these first mortgage bonds is payable unless and until a default
occurs on the installment purchase or loan agreements.
Senior Notes
In February 2000 and February 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, including its first mortgage bonds.
Bank Credit Arrangements
At the beginning of 2001, the Company had unused credit arrangements with banks
totaling $1.8 billion, of which $1.3 billion expires at various times during
2001, 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 20, 2001, 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
II-106
NOTES (continued)
Georgia Power Company 2000 Annual Report
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
2001 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, 2000 was $979 million.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $750 million commercial paper program that has the liquidity
support of committed bank credit arrangements. Average compensating balances
held under these committed facilities were not material in 2000.
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, 2000 and 1999, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million with an
interest rate of 8.1 percent. The lease agreement provides for payments that are
minimal in early years and escalate through the first 21 years of the lease. 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 is
being deferred as a cost to be recovered in the future as ordered by the GPSC.
At December 31, 2000 and 1999, the interest and lease amortization deferred on
the Balance Sheets are $55 million and $54 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.
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:
2000 1999
-------------------
(in millions)
Bond improvement fund requirements $ - $ 5
Capital lease - current portion 2 1
First mortgage bond maturities
and redemptions - 100
Pollution control bond maturities
and redemptions - 50
- ---------------------------------------------------------------
Total long-term debt $2 $156
===============================================================
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.
Redemption of Securities
The Company plans to continue, to the extent possible, a program of redeeming or
replacing debt and preferred securities in cases where opportunities exist to
reduce financing costs. Issues may be repurchased in the open market or called
at premiums as specified under terms of the issue. They may also be redeemed at
face value to meet improvement fund requirements, to meet replacement provisions
of the mortgage, or through use of proceeds from the sale of property pledged
under the mortgage.
II-107
NOTES (continued)
Georgia Power Company 2000 Annual Report
10. QUARTERLY FINANCIAL DATA
(UNAUDITED)
Summarized quarterly financial information for 2000 and 1999 is as follows:
Net Income
After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 2000 $ 992 $223 $ 94
June 2000 1,221 311 148
September 2000 1,545 537 283
December 2000 1,113 162 34
March 1999 $ 931 $224 $ 92
June 1999 1,092 299 138
September 1999 1,466 557 296
December 1999 968 115 15
- ---------------------------------------------------------------------
Under the GPSC retail rate order, the Company recorded $135 million and $85
million of accelerated amortization in 2000 and 1999, respectively, which were
recorded monthly as an operating expense. The fourth quarter December 1999
operating income has been restated to reflect the accelerated amortization as an
operating expense rather than as amortization of premium on reacquired debt. See
Note 3 to the financial statements under "Retail Rate Order" for additional
information.
The Company's business is influenced by seasonal weather conditions.
II-108
SELECTED FINANCIAL AND OPERATING DATA 1996-2000
Georgia Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,870,618 $4,456,675 $4,738,253 $4,385,717 $4,416,779
Net Income after Dividends
on Preferred Stock (in thousands) $559,420 $541,383 $570,228 $593,996 $580,327
Cash Dividends
on Common Stock (in thousands) $549,600 $543,000 $536,600 $520,000 $475,500
Return on Average Common Equity (percent) 13.66 14.02 14.61 14.53 13.73
Total Assets (in thousands) $13,133,609 $12,361,860 $12,033,618 $12,573,728 $13,006,635
Gross Property Additions (in thousands) $1,078,163 $790,464 $499,053 $475,921 $428,220
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stockholder's equity $4,249,544 $3,938,210 $3,784,172 $4,019,728 $4,154,281
Preferred stock 14,569 14,952 15,527 157,247 464,611
Company obligated mandatorily
redeemable preferred securities 789,250 789,250 689,250 689,250 325,000
Long-term debt 3,041,939 2,688,358 2,744,362 2,982,835 3,200,419
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,095,302 $7,430,770 $7,233,311 $7,849,060 $8,144,311
================================================================================================================================
Capitalization Ratios (percent):
Common stockholder's equity 52.5 53.0 52.3 51.2 51.0
Preferred stock 0.2 0.2 0.2 2.0 5.7
Company obligated mandatorily
redeemable preferred securities 9.7 10.6 9.5 8.8 4.0
Long-term debt 37.6 36.2 38.0 38.0 39.3
- --------------------------------------------------------------------------------------------------------------------------------
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 a2 a2 a2 a2 a2
Standard and Poor's BBB+ A- 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 1,669,566 1,632,450 1,596,488 1,561,675 1,531,453
Commercial 237,977 229,524 221,180 211,672 205,087
Industrial 8,533 8,958 9,485 9,988 10,424
Other 3,159 3,060 3,034 2,748 2,645
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,919,235 1,873,992 1,830,187 1,786,083 1,749,609
================================================================================================================================
Employees (year-end): 8,855 8,961 8,371 8,354 10,346
- --------------------------------------------------------------------------------------------------------------------------------
II-109
SELECTED FINANCIAL AND OPERATING DATA 1996-2000 (continued)
Georgia Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,535,684 $1,410,099 $ 1,486,699 $ 1,326,787 $ 1,371,033
Commercial 1,620,466 1,527,880 1,591,363 1,493,353 1,486,586
Industrial 1,154,789 1,143,001 1,170,881 1,110,311 1,118,633
Other 6,399 (30,892) 49,274 47,848 47,060
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 4,317,338 4,050,088 4,298,217 3,978,299 4,023,312
Sales for resale - non-affiliates 297,643 210,104 259,234 282,365 281,580
Sales for resale - affiliates 96,150 76,426 81,606 38,708 35,886
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,711,131 4,336,618 4,639,057 4,299,372 4,340,778
Other revenues 159,487 120,057 99,196 86,345 76,001
- ------------------------------------------------------------------------------------------------------------------------------
Total $4,870,618 $4,456,675 $4,738,253 $4,385,717 $4,416,779
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 20,693,481 19,404,709 19,481,486 17,295,022 17,826,451
Commercial 25,628,402 23,715,485 22,861,391 21,134,346 20,823,073
Industrial 27,543,265 27,300,355 27,283,147 26,701,685 26,191,831
Other 568,906 551,451 543,462 538,163 536,057
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 74,434,054 70,972,000 70,169,486 65,669,216 65,377,412
Sales for resale - non-affiliates 6,463,723 5,060,931 6,438,891 6,795,300 7,868,342
Sales for resale - affiliates 2,435,106 1,795,243 2,038,400 1,706,699 1,180,207
- ------------------------------------------------------------------------------------------------------------------------------
Total 83,332,883 77,828,174 78,646,777 74,171,215 74,425,961
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.42 7.27 7.63 7.67 7.69
Commercial 6.32 6.44 6.96 7.07 7.14
Industrial 4.19 4.19 4.29 4.16 4.27
Total retail 5.80 5.71 6.13 6.06 6.15
Sales for resale 4.43 4.18 4.02 3.78 3.51
Total sales 5.65 5.57 5.90 5.80 5.83
Residential Average Annual
Kilowatt-Hour Use Per Customer 12,520 12,006 12,314 11,171 11,763
Residential Average Annual
Revenue Per Customer $929.11 $872.47 $939.73 $857.01 $904.70
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 15,114 14,474 14,437 14,437 14,367
Maximum Peak-Hour Demand (megawatts):
Winter 12,014 11,568 11,959 10,407 10,410
Summer 14,930 14,575 13,923 13,153 12,914
Annual Load Factor (percent) 61.6 58.9 58.7 57.4 62.2
Plant Availability (percent):
Fossil-steam 86.1 84.3 86.0 85.8 85.2
Nuclear 91.5 89.3 91.6 88.8 89.3
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 62.3 63.0 62.3 64.3 60.4
Nuclear 17.4 18.0 18.3 18.8 18.2
Hydro 0.7 0.9 2.2 2.2 2.2
Oil and gas 1.8 1.6 2.2 0.6 0.5
Purchased power -
From non-affiliates 8.1 6.6 6.5 2.7 5.6
From affiliates 9.7 9.9 8.5 11.4 13.1
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
II-110
GULF POWER COMPANY
FINANCIAL SECTION
II-111
MANAGEMENT'S REPORT
Gulf Power Company 2000 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 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
Comptroller
and Chief Financial Officer
II-112
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, 2000 and 1999, 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, 2000. 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-123 through II-137)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 2000 and 1999, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 28, 2001
II-113
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 2000 net income after dividends on preferred stock was
$51.8 million, a decrease of $1.9 million from the previous year. In 1999,
earnings were $53.7 million, down $2.8 million when compared to 1998. The
decrease in earnings in 2000, as well as 1999, was primarily a result of higher
expenses than in the prior year.
Revenues
Operating revenues increased in 2000 when compared to 1999. The following table
summarizes the change in operating revenues for the past two years:
Increase (Decrease)
Amount From Prior Year
-------------------------------------
2000 2000 1999
-------------------------------------
(in thousands)
Retail --
Base Revenues $336,103 $3,771 $2,469
Regulatory cost
recovery and other 226,059 45,631 1,173
- ------------------------------------------------------------------
Total retail 562,162 49,402 3,642
- ------------------------------------------------------------------
Sales for resale--
Non-affiliates 66,890 4,537 461
Affiliates 66,995 885 23,468
- ------------------------------------------------------------------
Total sales for resale 133,885 5,422 23,929
Other operating
revenues 18,272 (14,604) (3,990)
- ------------------------------------------------------------------
Total operating
revenues $714,319 $40,220 $23,581
==================================================================
Percent change 6.0% 3.6%
- ------------------------------------------------------------------
Retail revenues of $562.2 million in 2000 increased $49.4 million, or 9.6
percent, from the prior year due primarily to the recovery of higher fuel and
purchased power costs. Retail base rate revenues increased $3.8 million due to
increased customer growth and hotter than normal weather, offset by a $10
million permanent annual rate reduction and $6.9 million of revenues subject to
refund based upon the current retail revenue sharing plan (See Note 3 to the
financial statements under "Retail Revenue Sharing Plan" for further
information). Retail revenues for 1999 increased $3.6 million, or 0.7 percent,
when compared to 1998 due primarily to an increase in the number of retail
customers served by the Company.
The 2000 increase in regulatory cost recovery and other retail revenues over
1999 is primarily attributable to higher fuel and purchased power costs. The
1999 increase in regulatory cost recovery and other retail revenues over 1998 is
primarily attributable to the recovery of increased purchased power capacity
costs. "Regulatory cost recovery and other" includes the following: recovery
provisions for fuel expense and the energy component of purchased power costs;
energy conservation costs; purchased power capacity costs; and environmental
compliance costs. 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 $133.9 million in 2000, an increase of $5.4 million, or
4.2 percent, over 1999 primarily due to additional energy sales. 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:
2000 1999 1998
----------------------------------------
(in thousands)
Capacity $20,270 $19,792 $22,503
Energy 21,922 20,251 14,556
- -------------------------------------------------------------
Total $42,192 $40,043 $37,059
=============================================================
Capacity revenues increased slightly in 2000 due to the recovery of higher
operating expenses experienced during the year. Capacity revenues had been
declining in prior years due to the decreasing net investment related to these
sales. This downward trend accelerated during 1999 as a result of a reduction in
the authorized rate of return on the equity component of the investment.
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 decreased in 2000 and in 1999 due primarily to the
retail recovery clause adjustments for the difference between recoverable costs
and the amounts actually reflected in current rates. See Notes 1 and 3 to the
financial statements under "Revenues and Regulatory Cost Recovery Clauses" and
"Environmental Cost Recovery," respectively, for further discussion.
II-114
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
Energy Sales
Kilowatt-hour sales for 2000 and the percent changes by year were as follows:
KWH Percent Change
----------------------------------
2000 2000 1999
----------------------------------
(millions)
Residential 4,790 7.1% 0.8%
Commercial 3,379 4.9 3.6
Industrial 1,925 4.3 0.7
Other 19 0.0 0.0
--------
Total retail 10,113 5.8 1.7
Sales for resale
Non-affiliates 1,705 9.2 16.4
Affiliates 1,917 (23.7) 42.9
--------
Total 13,735 0.7 9.0
=======================================================
In 2000, total retail energy sales increased when compared to 1999 due
primarily to an increase in the total number of customers and hotter than normal
weather. Total retail energy sales increased in 1999 when compared to 1998 due
to increases in the number of customers. See "Future Earnings Potential" for
information on the Company's initiatives to remain competitive and to meet
conservation goals set by the Florida Public Service Commission (FPSC).
An increase in energy sales for resale to non-affiliates of 9.2 percent in
2000 when compared to 1999 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 2000 increased $39.5 million, or 7.1 percent, over
the amount recorded in 1999 due primarily to higher fuel and purchased power
expenses. In 1999, total operating expenses increased $26.8 million, or 5.1
percent, compared to 1998 due primarily to higher fuel, purchased power, and
maintenance expenses offset by lower other operation expenses.
Fuel expenses in 2000, when compared to 1999, increased $6.7 million, or 3.2
percent, due primarily to an increase in average fuel costs. In 1999, fuel
expenses increased $11.5 million, or 5.9 percent, when compared to 1998. The
increases were the result of increased generation resulting from a higher demand
for energy.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
2000 1999 1998
-------------------------------
Total generation
(millions of kilowatt-hours) 12,866 13,095 11,986
Sources of generation
(percent)
Coal 98.2 97.4 98.0
Oil and gas 1.8 2.6 2.0
Average cost of fuel per net
kilowatt-hour generated
(cents)-- 1.68 1.60 1.69
- ---------------------------------------------------------------------
Purchased power expenses increased in 2000 by $25.5 million, or 44.7 percent,
over 1999 and purchased power expenses for 1999 increased over 1998 by $13.2
million, or 30.2 percent, due primarily to a higher demand for energy in both
years.
Depreciation and amortization expense increased $2.3 million, or 3.5 percent,
in 2000 when compared to 1999, 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. The $5.5 million, or 9.2 percent, increase
in 1999 compared to 1998 was due primarily to a reduction in the amortization of
gains from the 1998 sale of emission allowances.
Interest on long-term debt, which is included in "Interest expense",
increased $1.2 million, or 5.8 percent, in 2000 when compared to 1999 due
primarily to the issuance of $50 million of senior notes in August 1999. In 1999
interest on long-term debt increased $1.7 million, or 8.4 percent, when compared
to 1998 due primarily to the maturity of two first mortgage bond series in 1998
which were replaced by senior notes at a slightly higher interest rate, and 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
II-115
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
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
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 cost 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 $5.8 million in 2000. Pension income in 2001 is expected to be
less as a result of plan amendments. Future pension income is dependent on
several factors including trust earnings and changes to the plan.
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 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 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. 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 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 is currently planning to seek additional rate
relief to recover costs related to the Smith Unit 3 combined cycle facility
currently under construction and scheduled to be placed in-service in June of
2002.
For calendar year 2000, the Company's retail revenue range for sharing was
$352 million to $368 million. Actual retail revenues in 2000 were $362.4 million
and the Company recorded revenues subject to refund of $6.9 million. The
estimated refund with interest was reflected in customer billings in February
2001. For calendar year 2001, the Company's retail revenue range for sharing is
$358 million to $374 million. 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.
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. The Company is aggressively working to maintain and
expand its share of wholesale sales in the southeastern power markets.
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
II-116
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
tax issues. The commission's final report and recommendations are due to the
Governor and legislature by December 1, 2001. The commission submitted an
interim report to the state legislature that involves introducing more
competition into the wholesale production of electricity in Florida. If approved
by the legislature, the proposal would require utilities to turn over generating
assets to an unregulated affiliate company over a 6-year transition period. The
proposal would allow out of state companies to build merchant facilities and to
bid on new generation needs. The effects of any proposed changes cannot
presently be determined, but could have a material effect on the Company's
financial statements.
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 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 current energy crisis in
California. As a result of this crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation. The
inability of a company to recover its investments, including the regulatory
assets described in Note 1 to the financial statements, could have a material
adverse effect on 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 1996, the FPSC approved a new optional Commercial/Industrial Service Rider
(CISR), which is applicable to the rate schedules for the Company's largest
existing and potential customers who are able to show they have viable
alternatives to purchasing the Company's energy services. The CISR, approved as
a pilot program, provides the flexibility needed to enable the Company to offer
its services in a more competitive manner to these customers. The publicity of
the CISR ruling, increased competitive pressures, and general awareness of
customer choice pilots and proposals across the country have stimulated interest
on the part of customers in custom tailored offerings. The Company has
participated in one-on-one discussions with many of these customers, and has
negotiated and executed two Contract Service Agreements within the CISR pilot
program. The pilot program was scheduled to end in 2000; however, on February 6,
2001 the FPSC approved the Company's request to remove the original 48 month
limitation and allow the program to continue.
Every five years the FPSC establishes numeric demand side management goals.
The Company proposed numeric goals for the ten-year period from 2000 to 2009.
The proposed goals consisted of the total, cost-effective winter and summer peak
demand (kilowatts) and annual energy (kilowatt-hour) savings reasonably
achievable from demand side management for the residential and
commercial/industrial classes. The Company submitted its 2001 Demand Side
Management Plan to the FPSC on December 29, 2000. The plan describes the
proposed programs the Company will employ to reach the numeric goals. The plan
relies heavily on innovative pricing and energy efficient construction.
On December 20, 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. After participating in regional conferences with customers and other
members of the public to discuss the formation of RTOs, utilities were required
to make a filing with the FERC. Southern Company and its integrated utility
subsidiaries, including the Company, filed on October 16, 2000, a proposal for
the creation of an RTO. The proposal is for the formation of a for-profit
company that would have control of the bulk power transmission system of the
Company and any other participating utilities. Participants would have the
option to either maintain their ownership or divest, sell, or lease their assets
to the proposed RTO. If the FERC accepts the proposal as filed, the creation of
II-117
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
an RTO is not expected to have a material impact on the Company's financial
statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to allow holding companies to form exempt wholesale generators to sell power
largely free of 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 aggressively working to maintain and expand its share of
wholesale sales in the southeastern power markets. In January 2001, Southern
Company announced the formation of a new subsidiary -- Southern Power Company.
The new subsidiary will own, manage, and finance wholesale generating assets in
the Southeast. Southern Power will be the primary growth engine for Southern
Company's market-based energy business. Energy from its assets will be marketed
to wholesale customers under the Southern Company name.
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."
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.
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates 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, 2000, exposure from these activities was
not material.
New Accounting Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement
No. 133, Accounting for Derivative Instruments and Hedging Activities.
Statement No. 133, as amended, establishes accounting and reporting
standards for derivative instruments and for hedging activities. Statement
No. 133 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 Company may utilize financial instruments to reduce its exposure to
changes in interest rates depending on market conditions. The Company also
enters into commodity related forward contracts to limit exposure to changing
prices on certain fuel purchases and electricity purchases and sales.
Substantially all of these bulk energy purchases and sales meet the
definition of a derivative under Statement No. 133. In many cases, these
transactions meet the normal purchase and sale exception and the related
contracts will continue to be accounted for under the accrual method. Certain of
these instruments qualify as cash flow hedges resulting in the deferral of
related gains and losses in other comprehensive income until the hedged
transactions occur. Any ineffectiveness will be recognized currently in net
income. However, others will be required to be marked to market through current
period income.
The Company adopted Statement No. 133 effective January 1, 2001. The impact
on net income was immaterial. The application of the new rules is still evolving
and further guidance from FASB is expected, which could additionally impact the
Company's financial statements. Also, as wholesale energy markets mature, future
transactions could result in more volatility in net income and comprehensive
income.
11-118
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
Financial Condition
Overview
The Company's financial condition continues to be very solid. During 2000, gross
property additions were $95.8 million. Funds for the property additions were
provided by operating activities. See the Statements of Cash Flows for further
details.
Financing Activities
In 2000, there were no issuances or retirements of long-term debt. In 1999, the
Company sold $50 million of senior notes and long-term bank notes totaling $27
million were retired. See the Statements of Cash Flows for further details.
Composite financing rates for the years 1998 through 2000 as of year end were
as follows:
2000 1999 1998
-----------------------------
Composite interest rate on
long-term debt 6.2% 6.0% 6.1%
Composite rate on
trust preferred securities 7.3% 7.3% 7.3%
Composite preferred stock
dividend rate 5.1% 5.1% 5.1%
- -----------------------------------------------------------------
The composite interest rate on long-term debt increased in 2000 due to higher
interest rates on variable rate pollution control bonds.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $451 million for the three years
beginning in 2001 ($279 million in 2001, $96 million in 2002, and $76 million in
2003). These amounts include $199.2 million for the years 2001 and 2002 for the
estimated 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.
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. As a
result of a systemwide compliance strategy, some 50 generating units of Southern
Company were brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $300 million for Southern Company,
including 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.
Compliance for Phase II and initial ozone non-attainment requirements increased
Southern Company's total construction expenditures through 2000 by approximately
$100 million. Phase II compliance did not have a material impact on Gulf Power.
A significant portion of costs related to the acid rain and ozone
nonattainment 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.
II-119
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
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 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 recently dismissed certain challenges but 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
will address other legal challenges to these standards in mid-2001. If the
standards are eventually upheld, implementation could be required by 2007 to
2010.
In September 1998, the EPA issued the final regional nitrogen oxide reduction
rule to the states for implementation. Compliance is required by May 31, 2004.
The final rule affects 21 states, including Georgia. 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 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 (MACT) provisions of the Clean Air Act. This determination is being
challenged in the courts. 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 will likely
be required around 2010. Litigation of the BART rules is probable in the near
future.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C.
add to the uncertainties associated with BART guidance and the MACT
determination for mercury and other HAPS.
The EPA and state environmental regulatory agencies are also reviewing and
evaluating various other matters including: nitrogen oxide emission control
strategies for ozone non-attainment areas; additional controls for hazardous air
pollutant emissions; 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. 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 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 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
11-120
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
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.
On January 12, 2001, the EPA re-filed its claims against Alabama Power in
federal district court in Birmingham, Alabama. The EPA did not include the
system service company in the new complaint. Southern Company believes that its
integrated utilities 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.
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, 2000, the Company had approximately $4.4 million of cash and
cash equivalents and $53.5 million of unused committed lines of credit with
banks to meet its short-term cash needs. Refer to the Statements of Cash Flows
for details related to the Company's financing activities. See Note 4 to the
financial statements under "Bank Credit Arrangements" for additional
information.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company has no restrictions on the
amounts of unsecured indebtedness it may incur. However, 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 2000 Annual Report contains forward looking and historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "expects," "plans," "anticipates,"
"believes," "estimates," "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 extent and timing
of the entry of additional competition in the markets of the Company; potential
business strategies, including acquisitions or dispositions of assets or
11-121
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2000 Annual Report
businesses, which cannot be assured to be completed or beneficial; internal
restructuring or other restructuring options, that may be pursued by the
registrants; state and federal rate regulation in the United States; political,
legal and economic conditions and developments in the United States; financial
market conditions and the results of financing efforts; the impact of
fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
II-122
STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Gulf Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $562,162 $512,760 $509,118
Sales for resale --
Non-affiliates 66,890 62,354 61,893
Affiliates 66,995 66,110 42,642
Other revenues 18,272 32,875 36,865
- -----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 714,319 674,099 650,518
- -----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 215,744 209,031 197,462
Purchased power --
Non-affiliates 73,846 46,332 29,369
Affiliates 8,644 10,703 14,445
Other 117,146 114,670 119,011
Maintenance 56,281 57,830 57,286
Depreciation and amortization 66,873 64,589 59,129
Taxes other than income taxes 55,904 51,782 51,462
- -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 594,438 554,937 528,164
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income 119,881 119,162 122,354
Other Income (Expense):
Interest income 1,137 1,771 931
Other, net (4,126) (1,357) (2,339)
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 116,892 119,576 120,946
- -----------------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 28,085 26,861 25,556
Distributions on preferred securities of subsidiary 6,200 6,200 6,034
- -----------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 34,285 33,061 31,590
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 82,607 86,515 89,356
Income taxes (Note 7) 30,530 32,631 32,199
- -----------------------------------------------------------------------------------------------------------------------------
Net Income 52,077 53,884 57,157
Dividends on Preferred Stock 234 217 636
- -----------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 51,843 $ 53,667 $ 56,521
=============================================================================================================================
The accompanying notes are an integral part of these statements.
11-123
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
Gulf Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 52,077 $ 53,884 $ 57,157
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 69,915 68,721 69,633
Deferred income taxes and investment tax credits, net (12,516) (6,609) (4,684)
Other, net 10,686 3,735 3,463
Changes in certain current assets and liabilities --
Receivables, net (20,212) (10,484) 11,308
Fossil fuel stock 13,101 (5,656) (4,917)
Materials and supplies 1,055 (2,063) 609
Accounts payable 15,924 (2,023) 823
Provision for rate refund 7,203 - -
Other 12,521 7,030 (18,471)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 149,754 106,535 114,921
- ----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (95,807) (69,798) (69,731)
Other (4,432) (8,856) 5,990
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (100,239) (78,654) (63,741)
- ----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (12,000) 23,500 (15,500)
Proceeds --
Other long-term debt - 50,000 50,000
Preferred securities - - 45,000
Capital contributions from parent company 12,222 2,294 522
Retirements --
First mortgage bonds - - (45,000)
Other long-term debt (1,853) (27,074) (8,326)
Preferred stock - - (9,455)
Payment of preferred stock dividends (234) (271) (792)
Payment of common stock dividends (59,000) (61,300) (67,200)
Other (22) (246) (4,167)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (60,887) (13,097) (54,918)
- ----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (11,372) 14,784 (3,738)
Cash and Cash Equivalents at Beginning of Period 15,753 969 4,707
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 4,381 $ 15,753 $ 969
============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $32,277 $27,670 $28,044
Income taxes (net of refunds) 42,252 29,462 38,782
- ----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
11-124
BALANCE SHEETS
At December 31, 2000 and 1999
Gulf Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Assets 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 4,381 $ 15,753
Receivables --
Customer accounts receivable 69,820 55,108
Other accounts and notes receivable 2,179 4,325
Affiliated companies 15,026 7,104
Accumulated provision for uncollectible accounts (1,302) (1,026)
Fossil fuel stock, at average cost 16,768 29,869
Materials and supplies, at average cost 29,033 30,088
Regulatory clauses under recovery 2,112 11,611
Other 6,543 5,354
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 144,560 158,186
- ------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,892,023 1,853,664
Less accumulated provision for depreciation 867,260 821,970
- ------------------------------------------------------------------------------------------------------------------------------
1,024,763 1,031,694
Construction work in progress 71,008 34,164
- ------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,095,771 1,065,858
- ------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 4,510 1,481
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 7) 15,963 25,264
Prepaid pension costs (Note 2) 23,491 17,734
Debt expense, being amortized 2,392 2,526
Premium on reacquired debt, being amortized 15,866 17,360
Other 12,943 20,086
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 70,655 82,970
- ------------------------------------------------------------------------------------------------------------------------------
Total Assets $1,315,496 $1,308,495
==============================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-125
BALANCE SHEETS
At December 31, 2000 and 1999
Gulf Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Notes payable $ 43,000 $ 55,000
Accounts payable --
Affiliated 17,558 14,878
Other 38,153 22,581
Customer deposits 13,474 12,778
Taxes accrued --
Income taxes 3,864 4,889
Other 8,749 7,707
Interest accrued 8,324 9,255
Provision for rate refund 7,203 -
Vacation pay accrued 4,512 4,199
Regulatory clauses over recovery 6,848 3,125
Other 1,584 1,836
- ----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 153,269 136,248
- ----------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 365,993 367,449
- ----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 155,074 162,776
Deferred credits related to income taxes (Note 7) 38,255 49,693
Accumulated deferred investment tax credits 25,792 27,712
Employee benefits provisions 34,507 31,735
Other 25,992 21,333
- ----------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 279,620 293,249
- ----------------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 85,000 85,000
- ----------------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 4,236 4,236
- ----------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 427,378 422,313
- ----------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,315,496 $1,308,495
============================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-126
STATEMENTS OF CAPITALIZATION
At December 31, 2000 and 1999
Gulf Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- -------------
July 1, 2003 6.125% $ 30,000 $ 30,000
November 1, 2006 6.50% 25,000 25,000
January 1, 2026 6.875% 30,000 30,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 85,000 85,000
- ------------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
7.50% due June 30, 2037 20,000 20,000
6.70% due June 30, 2038 48,073 49,926
7.05% due August 15, 2004 50,000 50,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 118,073 119,926
- ------------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.25% to 6.30% due 2006-2026 108,700 108,700
Variable rates (3.70% at 1/1/00)
due 2024 - 20,000
Non-collateralized:
Variable rates (5.10% to 5.30% at 1/1/01)
due 2022-2024 60,930 40,930
- ------------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 169,630 169,630
- ------------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (6,710) (7,107)
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $23.2 million) 365,993 367,449 41.5% 41.8%
- ------------------------------------------------------------------------------------------------------------------------------------
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 0.5% 0.5%
- ------------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
7.00% 45,000 45,000
7.63% 40,000 40,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $6.2 million) 85,000 85,000 9.6% 9.7%
- ------------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized and outstanding -
992,717 shares in 2000 and 1999 38,060 38,060
Paid-in capital 233,476 221,254
Premium on preferred stock 12 12
Retained earnings 155,830 162,987
- ------------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 427,378 422,313 48.4% 48.0%
- ------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $882,607 $878,998 100.0% 100.0%
====================================================================================================================================
The accompanying notes are an integral part of these statements.
11-127
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2000, 1999, and 1998
Gulf Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1998 $38,060 $218,438 $12 $172,208 $428,718
Net income after dividends on preferred stock - - - 56,521 56,521
Capital contributions from parent company - 522 - - 522
Cash dividends on common stock - - - (57,200) (57,200)
Other - - - (909) (909)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 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 - - - (61,300) (61,300)
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
====================================================================================================================================
The accompanying notes are an integral part of these statements.
II-128
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2000 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Gulf Power Company is a wholly owned subsidiary of Southern Company, which is
the parent company of five integrated Southeast utilities, Southern Company
Services (SCS), Southern Communications Services (Southern LINC), Southern
Company Energy Solutions, Mirant Corporation (Mirant) - formerly Southern
Energy, Inc., -- Southern Nuclear Operating Company (Southern Nuclear), and
other direct and indirect subsidiaries. The integrated Southeast utilities --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- provide electric service in four states. Gulf Power Company provides
electric service to the northwest panhandle of Florida. Contracts among the
integrated Southeast utilities -- related to jointly owned generating
facilities, interconnecting transmission lines, and the exchange of electric
power --are regulated by the Federal Energy Regulatory Commission (FERC) and/or
the Securities and Exchange Commission (SEC). 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 Company Energy Solutions develops new business opportunities
related to energy products and services. Southern Nuclear provides services to
Southern Company's nuclear power plants. Mirant acquires, develops, builds,
owns, and operates power production and delivery facilities and provides a broad
range of energy-related services to utilities and industrial companies in
selected countries around the world. Mirant businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the 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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension 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
million, $43 million, and $40 million during 2000, 1999, and 1998, 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:
2000 1999
--------------------------
(in thousands)
Deferred income tax charges $ 15,963 $ 25,264
Deferred loss on reacquired
debt 15,866 17,360
Environmental remediation 7,638 5,745
Vacation pay 4,512 4,199
Regulatory clauses under (over)
recovery, net (4,736) 8,486
Accumulated provision for
rate refunds (7,203) -
Accumulated provision for
property damage (8,731) (5,528)
Deferred income tax credits (38,255) (49,693)
Other, net (1,074) (1,255)
- ------------------------------------------------------------------
Total $ (16,020) $ 4,578
==================================================================
II-129
NOTES (continued)
Gulf Power Company 2000 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 any impairment to other assets, including plant, and write down the
assets, if impaired, to their fair value.
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 3.8 percent in 2000,
1999, and 1998. 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.
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. The Company is included
in the consolidated federal income tax return of Southern Company.
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.
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
The Company's 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, 2000 $365,993 $364,697
At December 31, 1999 $367,449 $349,791
Capital trust preferred
securities:
At December 31, 2000 $85,000 $80,988
At December 31, 1999 $85,000 $69,092
- --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on
either closing market prices or closing prices of comparable instruments.
II-130
NOTES (continued)
Gulf Power Company 2000 Annual Report
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 $1.2 million and $1.8 million
at December 31, 2000 and 1999, 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, 2000 and 1999, the
accumulated provision for property damage was $8.7 million and $5.5 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 $3.5 million in 2000, $5.5
million in 1999, and $6.5 million in 1998 to the accumulated provision for
property damage. The Company charged $0.3 million, $1.6 million, and $4.2
million against the provision account in 2000, 1999, and 1998 respectively.
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
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 effects of these changes will be to increase the Company's annual
pension and postretirement benefits costs by approximately $1.2 million and $0.6
million, respectively. 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
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $141,967 $143,012
Service cost 4,282 4,490
Interest cost 10,394 9,440
Benefits paid (6,973) (6,862)
Actuarial gain and
employee transfers, net (689) (8,113)
- ---------------------------------------------------------------
Balance at end of year $148,981 $141,967
===============================================================
Plan Assets
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $241,485 $212,934
Actual return on plan assets 43,833 35,971
Benefits paid (6,973) (6,862)
Employee transfers 4,921 (558)
- ---------------------------------------------------------------
Balance at end of year $283,266 $241,485
===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999
- ---------------------------------------------------------------
(in thousands)
Funded status $ 134,286 $ 99,518
Unrecognized transition
obligation (3,602) (4,323)
Unrecognized prior
service cost 4,121 4,495
Unrecognized net gain (111,314) (81,956)
- ---------------------------------------------------------------
Prepaid asset recognized
in the Balance Sheets $ 23,491 $ 17,734
===============================================================
II-131
NOTES (continued)
Gulf Power Company 2000 Annual Report
Components of the pension plan's net periodic cost were as follows:
2000 1999 1998
- -------------------------------------------------------------------
Service cost $ 4,282 $ 4,490 $ 4,107
Interest cost 10,394 9,440 9,572
Expected return on
plan assets (17,504) (15,968) (14,827)
Recognized net gain (2,582) (1,579) (1,891)
Net amortization (347) (347) (347)
- -------------------------------------------------------------------
Net pension income $ (5,757) $ (3,964) $ (3,386)
===================================================================
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
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $48,010 $49,303
Service cost 896 1,087
Interest cost 3,515 3,261
Benefits paid (1,462) (1,177)
Actuarial gain and
employee transfers, net (934) (4,464)
- ---------------------------------------------------------------
Balance at end of year $50,025 $48,010
===============================================================
Plan Assets
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $11,196 $ 9,603
Actual return on plan assets 2,079 1,525
Employer contributions 1,575 1,245
Benefits paid (1,462) (1,177)
- ---------------------------------------------------------------
Balance at end of year $13,388 $11,196
===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2000 1999
- ---------------------------------------------------------------
(in thousands)
Funded status $(36,638) $(36,814)
Unrecognized transition
obligation 4,368 4,723
Unrecognized prior
service cost 2,582 2,741
Unrecognized net loss 496 2,620
Fourth quarter contributions 316 300
- ---------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(28,876) $(26,430)
===============================================================
Components of the postretirement plan's net periodic cost were
as follows:
2000 1999 1998
- ----------------------------------------------------------------
Service cost $ 896 $1,087 $ 946
Interest cost 3,515 3,261 3,123
Expected return on
plan assets (901) (794) (717)
Transition obligation 355 356 356
Prior service cost 159 159 119
Recognized net loss 13 264 128
- ----------------------------------------------------------------
Net postretirement cost $4,037 $4,333 $3,955
================================================================
The weighted average rates assumed in the actuarial calculations for
both the pension plan and postretirement benefits were:
2000 1999
- --------------------------------------------------------
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 7.3
percent for 2000, decreasing gradually to 5.5 percent through the year 2005, and
remaining at that level thereafter.
II-132
NOTES (continued)
Gulf Power Company 2000 Annual Report
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, 2000 as follows (in thousands):
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
Benefit obligation $3,187 $2,874
Service and interest costs $278 $247
===============================================================
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 2000, 1999, and 1998 were $2.2
million, $2.0 million, and $2.0 million, respectively.
Work Force Reduction Programs
The Company recorded costs related to work force reduction programs of $0.6
million in 2000, $0.2 million in 1999, and $2.8 million in 1998. The Company has
also incurred its pro rata share for the costs of affiliated companies'
programs. The costs related to these programs were $1.2 million for 2000, $0.6
million for 1999, and $0.2 million for 1998. The Company has expensed all costs
related to these work force reduction programs.
3. CONTINGENCIES AND REGULATORY
MATTERS
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 all 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 2000, 1999, and 1998, the Company
recorded ECRC revenues of $9.9 million, $11.5 million, and $8.0 million,
respectively.
At December 31, 2000, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $7.6 million. These
estimated costs are expected to be expended from 2001 through 2006. 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 $6.4 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
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 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 equipment when performing maintenance
and construction at coal burning plants constructed or under construction prior
to 1978. The Company believes that its integrated utilities 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
II-133
NOTES (continued)
Gulf Power Company 2000 Annual Report
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 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 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 is currently planning to seek
additional rate relief to recover costs related to the Smith Unit 3
combined cycle facility scheduled to be placed in-service in June of 2002.
For calendar year 2000, the Company's retail revenue range for sharing was
$352 million to $368 million to be shared between the Company and its retail
customers on the one-third/two-thirds basis. Actual retail revenues in 2000 were
$362.4 million and the Company recorded revenues subject to refund of $6.9
million. The estimated refund with interest of $0.3 million was reflected in
customer billings in February 2001. In addition to the refund the Company
amortized $1 million of the regulatory assets related to the corporate office.
For calendar year 2001, the Company's retail revenue range for sharing is $358
million to $374 million. 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.
4. FINANCING AND COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $279 million in 2001, $96 million in 2002, and
$76 million in 2003. 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, 2000, significant purchase commitments were outstanding in
connection with the construction program. The Company has budgeted $199.2
million for the years 2001 and 2002 for the estimated 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.
Bank Credit Arrangements
At December 31, 2000, the Company had $61.5 million of lines of credit with
banks subject to renewal June 1 of each year, of which $53.5 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. In addition, the Company
has bid-loan facilities with seven major money center banks that total $130
million, of which $35 million was committed at December 31, 2000.
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.
II-134
NOTES (continued)
Gulf Power Company 2000 Annual Report
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, 2000 were as follows:
Year Fuel
--------- ----------------
(in millions)
2001 $139
2002 91
2003 90
2004 92
2005 93
2006-2024 473
-------------------------------------------------------------
Total commitments $978
=============================================================
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 renew the lease. In 1997, three additional lease
agreements for 120 cars each were entered into for three years, with a monthly
renewal option for up to an additional nine months.
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 $2.1 million in 2000 and $2.8 million in 1999.
The annual amounts for 2001 through 2005 are expected to be $1.9 million, $1.9
million, $1.9 million, $2.0 million, and $2.0 million, respectively, and after
2005 are expected to total $13.8 million.
5. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel, a steam-electric
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 the plant.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant
Scherer is a steam-electric 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, 2000, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:
Plant Scherer Plant
Unit No. 3 Daniel
(coal-fired) (coal-fired)
-----------------------------
(in thousands)
Plant In Service $185,778(1) $232,074
Accumulated Depreciation $70,207 $118,504
Construction Work in Progress $252 $2,006
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: 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 $20.3 million in 2000, $19.8 million in 1999, and $22.5 million in 1998.
II-135
NOTES (continued)
Gulf Power Company 2000 Annual Report
Capacity revenues increased slightly in 2000 due to the recovery of higher
operating expenses experienced during the year.
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, 209
megawatts of net dependable capacity were sold by the Company during 2000. Sales
will increase slightly to 210 megawatts per year in 2001 and remain close to
that level, 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.
7. INCOME TAXES
At December 31, 2000, the tax-related regulatory assets to be recovered from
customers were $16.0 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, 2000,
the tax-related regulatory liabilities to be credited to customers were $38.3
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:
2000 1999 1998
------------------------------------
(in thousands)
Total provision for income taxes:
Federal--
Current $37,250 $33,973 $31,746
Deferred (11,159) (6,107) (4,467)
- --------------------------------------------------------------------
26,091 27,866 27,279
- --------------------------------------------------------------------
State--
Current 5,796 5,267 5,137
Deferred (1,357) (502) (217)
- --------------------------------------------------------------------
4,439 4,765 4,920
- --------------------------------------------------------------------
Total $30,530 $32,631 $32,199
====================================================================
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:
2000 1999
---------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $172,646 $168,662
Other 14,262 24,272
- ---------------------------------------------------------------------
Total 186,908 192,934
- ---------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 8,703 9,293
Postretirement benefits 9,205 8,456
Other 14,742 12,526
- ---------------------------------------------------------------------
Total 32,650 30,275
- ---------------------------------------------------------------------
Net deferred tax liabilities 154,258 162,659
Less current portion, net (816) (117)
- ---------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $155,074 $162,776
=====================================================================
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 $1.9 million in 2000, 1999, and 1998. At December 31,
2000, 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:
2000 1999 1998
----------------------------
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 (1) - (2)
- ----------------------------------------------------------------
Effective income tax rate 37% 38% 36%
================================================================
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.
II-136
NOTES (continued)
Gulf Power Company 2000 Annual Report
8. COMPANY OBLIGATED MANDATORILY
REDEEMABLE 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.
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 and Trust II. Trust I and Trust II are subsidiaries of the
Company, and accordingly are consolidated in the Company's financial statements.
9. SECURITIES DUE WITHIN ONE YEAR
At December 31, 2000, the Company had an improvement fund requirement of
$850,000. 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.
10. COMMON STOCK 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, 2000, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.
11. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 2000 and 1999 are as follows:
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
- --------------------------------------------------------------------
(in thousands)
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
March 1999 $134,506 $15,665 $ 4,799
June 1999 166,815 29,253 13,226
September 1999 218,264 54,429 28,582
December 1989 154,514 19,815 7,060
- --------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-137
SELECTED FINANCIAL AND OPERATING DATA 1996-2000
Gulf Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $714,319 $674,099 $650,518 $625,856 $634,365
Net Income after Dividends
on Preferred Stock (in thousands) $51,843 $53,667 $56,521 $57,610 $57,845
Cash Dividends
on Common Stock (in thousands) $59,000 $61,300 $57,200 $64,600 $58,300
Return on Average Common Equity (percent) 12.20 12.63 13.20 13.33 13.27
Total Assets (in thousands) $1,315,496 $1,308,495 $1,267,901 $1,265,612 $1,308,366
Gross Property Additions (in thousands) $95,807 $69,798 $69,731 $54,289 $61,386
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $427,378 $422,313 $427,652 $428,718 $435,758
Preferred stock 4,236 4,236 4,236 13,691 65,102
Company obligated mandatorily
redeemable preferred securities 85,000 85,000 85,000 40,000 -
Long-term debt 365,993 367,449 317,341 296,993 331,880
- -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $882,607 $878,998 $834,229 $779,402 $832,740
===================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 48.4 48.0 51.3 55.0 52.3
Preferred stock 0.5 0.5 0.5 1.8 7.8
Company obligated mandatorily
redeemable preferred securities 9.6 9.7 10.2 5.1 -
Long-term debt 41.5 41.8 38.0 38.1 39.9
- -----------------------------------------------------------------------------------------------------------------------------------
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+ AA- AA- AA- A+
Fitch AA-* AA- AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's BBB+ A- A A A
Fitch A* A A+ A+ A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 -
Standard and Poor's A A A A -
Fitch A+* A+ A+ A+ -
===================================================================================================================================
Customers (year-end):
Residential 321,731 315,240 307,077 300,257 291,196
Commercial 47,666 47,728 46,370 44,589 43,196
Industrial 280 267 257 267 278
Other 442 316 268 264 162
- -----------------------------------------------------------------------------------------------------------------------------------
Total 370,119 363,551 353,972 345,377 334,832
===================================================================================================================================
Employees (year-end): 1,327 1,339 1,328 1,328 1,384
- -----------------------------------------------------------------------------------------------------------------------------------
*Effective 1/22/01 the Fitch Security Ratings for First Mortgage Bonds,
Preferred Stock, and Unsecured Long-Term Debt are A+, A-, and A respectively.
II-138
SELECTED FINANCIAL AND OPERATING DATA 1996-2000 (continued)
Gulf Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 308,728 $277,311 $ 276,208 $ 277,609 $ 285,498
Commercial 181,584 165,871 160,960 164,435 164,181
Industrial 76,539 67,404 69,850 77,492 78,994
Other (4,689) 2,174 2,100 2,083 2,056
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 562,162 512,760 509,118 521,619 530,729
Sales for resale - non-affiliates 66,890 62,354 61,893 63,697 63,201
Sales for resale - affiliates 66,995 66,110 42,642 16,760 17,762
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 696,047 641,224 613,653 602,076 611,692
Other revenues 18,272 32,875 36,865 23,780 22,673
- ------------------------------------------------------------------------------------------------------------------------------
Total $714,319 $674,099 $650,518 $625,856 $634,365
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 4,790,038 4,471,118 4,437,558 4,119,492 4,159,924
Commercial 3,379,449 3,222,532 3,111,933 2,897,887 2,808,634
Industrial 1,924,749 1,846,237 1,833,575 1,903,050 1,808,086
Other 18,730 19,296 18,952 18,101 17,815
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 0,112,966 9,559,183 9,402,018 8,938,530 8,794,459
Sales for resale - non-affiliates 1,705,486 1,561,972 1,341,990 1,531,179 1,534,097
Sales for resale - affiliates 1,916,526 2,511,983 1,758,150 848,135 709,647
- ------------------------------------------------------------------------------------------------------------------------------
Total 3,734,978 13,633,138 12,502,158 11,317,844 11,038,203
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.45 6.20 6.22 6.74 6.86
Commercial 5.37 5.15 5.17 5.67 5.85
Industrial 3.98 3.65 3.81 4.07 4.37
Total retail 5.56 5.36 5.41 5.84 6.03
Sales for resale 3.70 3.15 3.37 3.38 3.61
Total sales 5.07 4.70 4.91 5.32 5.54
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,992 14,318 14,577 13,894 14,457
Residential Average Annual
Revenue Per Customer $966.26 $888.01 $907.35 $936.30 $992.17
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,188 2,188 2,188 2,174 2,174
Maximum Peak-Hour Demand (megawatts):
Winter 2,154 2,085 2,040 1,844 2,136
Summer 2,285 2,161 2,146 2,032 1,961
Annual Load Factor (percent) 55.4 55.2 55.3 55.5 51.4
Plant Availability Fossil-Steam (percent): 85.2 87.2 87.6 91.0 91.8
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 87.8 89.8 89.2 87.1 87.8
Oil and gas 1.6 2.5 2.0 0.4 0.5
Purchased power -
From non-affiliates 7.6 5.9 5.5 3.5 2.7
From affiliates 3.0 1.8 3.3 9.0 9.0
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
II-139
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-140
MANAGEMENT'S REPORT
Mississippi Power Company 2000 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 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 upon 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/Dwight H. Evans
Dwight H. Evans
President and Chief Executive Officer
/s/Michael W. Southern
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
II-141
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 2000 and 1999, 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, 2000. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-151 through II-166)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 2000 and 1999, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 28, 2001
II-142
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 2000 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's 2000 net income after dividends on preferred stock
of $55 million increased $0.2 million over 1999 earnings of $54.8 million, which
were $0.3 million less than 1998 earnings of $55.1 million.
Revenues
Operating revenues for the Company in 2000 and the changes from the prior year
are as follows:
Increase (Decrease)
Amount From Prior Year
------ ----------------------
2000 2000 1999
---------------------------------------
(in millions)
Retail --
Base Revenues $287,253 $ (5,854) $ 17,462
Fuel cost recovery
and other 211,298 34,971 9,405
----------------------------------------------------------------
Total retail 498,551 29,117 26,867
----------------------------------------------------------------
Sales for resale --
Non-affiliates 145,931 14,927 9,779
Affiliates 27,915 8,469 1,161
----------------------------------------------------------------
Total sales for resale 173,846 23,396 10,940
Other operating
revenues 15,205 2,085 66
----------------------------------------------------------------
Operating revenues $687,602 $54,598 $ 37,873
==================================================================
Percent change 8.6% 6.4%
------------------------------------------------------------------
Total retail revenues for 2000 increased approximately 6.2 percent when
compared to 1999. The increase resulted primarily from continued growth in the
service area, a positive impact of weather and additional fuel revenues. Retail
revenues for 1999 reflected a 6.1 percent increase over the prior year due to
the continued growth in the service area, increased fuel revenues, and a true-up
of the unbilled revenue estimate.
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.
Energy sales to non-affiliates include economy sales and amounts sold under
short-term contracts. 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 increased 10.9 percent in 2000 and
10.2 percent in 1999, with the related revenues rising 10.8 percent and 12.1
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 2000 and 1999 primarily due to power
marketing activities. These increases were offset by increases in purchased
power from non-affiliates and, as a result, had no significant effect on net
income.
Sales to affiliated companies within the Southern Company electric system
will vary from year to year depending on demand and the availability and cost of
generating resources at each company. These sales have no material impact on
earnings.
Below is a breakdown of kilowatt-hour sales for 2000 and the percent change
for the last two years:
2000 Percent Change
------------- ---------------------------
KWH 2000 1999
---------------------------
(in millions)
Residential 2,286 1.7% -
Commercial 2,883 1.3 8.5%
Industrial 4,376 (0.7) 18.2
Other 41 2.5 0.8
-------
Total retail 9,586 0.5 10.4
Sales for
Resale --
Non-affiliates 3,675 12.9 3.1
Affiliates 453 (16.2) (2.2)
-------
Total 13,714 2.8 8.0
==================================================================
Total retail kilowatt-hour sales increased slightly in 2000 when compared to
1999 sales, which included an unbilled revenue true-up of approximately 3.5
percent. The increase primarily resulted from the continued growth in the
service area and the positive impact of weather. Excluding the impact of the
unbilled revenue true-up, all retail customer classes experienced growth in 2000
II-143
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2000 Annual Report
due to the positive impact of weather, increased tourism, and continued growth
in the service area. In 1999, increased tourism and strong growth impacted
commercial sales, while industrial sales were impacted by increased production
by several larger industrial customers, including one which was shut down in
1998 by Hurricane Georges.
Expenses
Total operating expenses were $565 million in 2000 reflecting an increase of $52
million or 10.1 percent over the prior year. The increase was due primarily to
higher fuel and purchased power expenses. In 1999, total operating expenses
increased by 6.9 percent over the prior year due primarily to higher fuel
expenses.
Fuel costs are the single largest expense for the Company. Fuel expenses for
2000 and 1999 increased 10.7 percent and 10.3 percent, respectively. The
increase for each year was due to increased generation and a higher average cost
of fuel. The increased generation was due to higher demand for energy across the
Southern Company electric system.
In 2000, expenses related to purchased power from non-affiliates increased
40.0 percent, while expenses related to purchased power from affiliates
increased 64.7 percent which, in total, resulted in a 51 percent increase when
compared to 1999. This increase consisted mostly of energy purchased for power
marketing activities which was resold to non-affiliated third parties and had no
significant effect on net income. 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:
2000 1999 1998
-----------------------------
Total generation
(millions of kilowatt
hours) 11,688 11,599 10,610
Sources of generation
(percent) --
Coal 83 81 80
Gas 17 19 20
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.80 1.65 1.62
- -----------------------------------------------------------------
Other operation expenses decreased 8.2 percent in 2000 primarily due to a
decrease in administrative and general expenses. In 1999, other operation
expense increased 13.9 percent primarily due to the amortization of costs
associated with the workforce reduction plan and higher distribution expenses.
Maintenance expense in 2000 increased due to additional scheduled maintenance,
while maintenance expense in 1999 decreased due to reduced scheduled
maintenance. In 2000, depreciation expenses increased slightly due to growth in
plant investment and a new composite depreciation rate, which became effective
January 2000. Comparisons of taxes other than income taxes for 2000 and 1999
show increases of 1.7 percent and 4.2 percent, respectively, due to higher
municipal franchise taxes resulting from higher retail revenues. Interest on
long-term debt increased in 2000 due to higher interest rates and increased 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 or the
partially offsetting gain that arises through financing facilities with
II-144
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2000 Annual Report
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of the Company's 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, 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 Environmental Compliance Overview Plan (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) regulations. 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's 2000 ECO Plan filed in January 2000 was
approved as filed, and resulted in a slight decrease in customer prices. The
Company filed its 2001 ECO Plan in January 2001 and, if approved as filed, it
will result in a slight increase in customer prices. Refer to 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."
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.
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and 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 transmission 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
II-145
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2000 Annual Report
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 transmission, prices, and recovery of any stranded costs. The
inability of the Company to recover its investment, including regulatory assets,
could have a material adverse effect on the financial condition of the Company.
The Company is attempting to minimize or reduce its cost exposure. 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 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.
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.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final ruling on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. After participating in regional conferences with customers and other
members of the public to discuss the formation of RTOs, utilities were required
to make a filing with the FERC. On October 16, 2000, Southern Company and its
integrated utilities including the Company filed a proposal for the creation of
an RTO. The proposal is for the formation of a for-profit company that would
have control of the bulk power transmission system of the Company and any other
participating utilities. Participants would have the option to either maintain
their ownership or divest, sell, or lease their assets to the proposed RTO. If
the FERC accepts the proposal as filed, the creation of an RTO is not expected
to have a material impact on the Company's financial statements. The outcome of
this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935
(PUHCA) to allow holding companies to form exempt wholesale generators to sell
power largely free of 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 aggressively working to maintain and expand its share of
wholesale sales in the southeastern power markets. In January 2001, Southern
Company announced the formation of a new subsidiary - Southern Power Company.
The new subsidiary will own, manage, and finance wholesale generating assets in
the Southeast. Southern Power will be the primary growth engine for Southern
Company's market-based energy business. Energy from its assets will be marketed
to wholesale customers under the Southern Company name.
In accordance with FASB Statement No. 87, Employers' Accounting for
Pensions, the Company recorded non-cash pension income of approximately $4.2
million in 2000. Pension income in 2001 is expected to be less as a result of
plan amendments. Future pension income is dependent on several factors including
trust earnings and changes to the plan. For more information, see Note 2.
The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters."
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.
II-146
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2000 Annual Report
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, 2000,
exposure from these activities was not material to the Company's financial
statements. Also, based on the Company's overall interest rate exposure at
December 31, 2000, a near-term 100 basis point change in interest rates would
not materially affect the financial statements.
New Accounting Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement
No. 133, Accounting for Derivative Instruments and Hedging Activities.
Statement No. 133, as amended, establishes accounting and reporting
standards for derivative instruments and for hedging activities. Statement
No. 133 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.
Substantially all of the Company's bulk energy purchases and sales meet the
definition of a derivative under Statement No. 133. In many cases, these
transactions meet the normal purchase and sale exception and the related
contracts will continue to be accounted for under the accrual method. Certain of
these instruments qualify as cash flow hedges resulting in the deferral of
related gains and losses in other comprehensive income until the hedged
transactions occur. Any ineffectiveness will be recognized currently in net
income. However, others will be required to be marked to market through current
period income.
The Company adopted Statement No. 133 effective January 1, 2001. The impact
on net income was immaterial. The application of the new rules is still evolving
and further guidance from FASB is expected, which could additionally impact the
Company's financial statements. Also, as wholesale energy markets mature, future
transactions could result in more volatility in net income and comprehensive
income.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition during 2000 was the
addition of approximately $81 million to utility plant. Funding for these
additions and other capital requirements were derived primarily from operations.
The Statements of Cash Flows provide additional details.
Financing Activity
In March 2000, the Company issued $100 million of floating rate senior notes due
March 28, 2002. The proceeds were used to prepay bank loans of $45 million
maturing in November 2001 and $5 million maturing in October 2002. The balance
of the $100 million was used to repay a portion of the Company's outstanding
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 increased for the year 2000 when compared to 1998
and 1999. As of year-end , the composite rates were as follows:
2000 1999 1998
----------------------------
Composite interest rate on
long-term debt 6.41% 6.19% 6.14%
Composite preferred stock
dividend rate 6.33% 6.33% 6.33%
Composite interest rate on
preferred securities 7.75% 7.75% 7.75%
------------------------------------------------------------
In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding, Limited Partnership ("Escatawpa"), that calls for the
Company to design and construct, as agent for Escatawpa, a 1,064 megawatt
natural gas combined cycle facility. It is anticipated that the total project
will cost approximately $400 million, and upon project completion in mid 2001,
the Company intends to lease the facility for an initial term of approximately
10 years. It is anticipated that the annual lease payments will approximate $32
million during the initial term.
II-147
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2000 Annual Report
Capital Structure
At year-end 2000, the Company's ratio of common equity to total capitalization,
excluding long-term debt due within one year, decreased from 50.2 percent in
1999, to 48.1 percent.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$191 million ($62 million in 2001, $60 million in 2002, and $69 million in
2003). 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.
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $135 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.
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
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,
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 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 the system service company's motion
to dismiss on the grounds that it neither owned nor operated the generating
units involved in the proceedings. On January 12, 2001, the EPA re-filed its
claims against Alabama Power in federal district court in Birmingham, Alabama.
The EPA did not include SCS in the new complaint. 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 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. 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.
As a result of a systemwide compliance strategy, some 50 generating units of
Southern Company were brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $300 million for Southern Company,
including approximately $65 million for the Company.
II-148
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2000 Annual Report
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
the Company's total construction expenditures through 2000 by approximately $100
million. 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 recently dismissed certain challenges but 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
will address other legal challenges to these standards in mid-2001. A decision
is expected in the spring of 2001. If the standards are eventually upheld,
implementation could be required by 2007 to 2010.
In September 1998, the EPA issued the final regional nitrogen oxide
reduction rules to the states for implementation. Compliance is required by May
31, 2004. The final rules affect 21 states that at present 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, 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 (MACT) provisions of the Clean Air Act. This determination is being
challenged in the courts. 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 would likely
be required around 2010. Litigation of the BART rules is probable in the near
future.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C.
add to the uncertainties associated with BART guidance and the MACT
determination for mercury and other HAPS.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: emission control strategies for ozone
non-attainment areas; additional controls for hazardous air pollutant emissions;
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 costs.
II-149
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2000 Annual Report
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 lawsuits alleging damages
caused by electromagnetic fields or other environmental concerns. The likelihood
or outcome of such potential lawsuits cannot be determined at this time.
Sources of Capital
To meet short-term cash needs and contingencies, the Company had at December 31,
2000 approximately $7.5 million of cash and cash equivalents and approximately
$117 million of unused committed credit agreements. The Company had $56 million
of short-term notes payable outstanding at year-end 2000.
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 issued unsecured debt in 1998.
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.
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," "expects," "plans," "anticipates,"
"believes," "estimates," "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 against the Company;
the extent and timing of the entry of additional competition in the markets of
the Company; potential business strategies, including acquisitions or
dispositions of assets or businesses, which cannot be assured to be completed or
beneficial; internal restructuring or other restructuring options, that may be
pursued by the Company; state and federal rate regulation in the United States;
political, legal and economic conditions and developments in the United States;
financial market conditions and the results of financing efforts; the impact of
fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
II-150
STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Mississippi Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $498,551 $469,434 $442,567
Sales for resale --
Non-affiliates 145,931 131,004 121,225
Affiliates 27,915 19,446 18,285
Other revenues 15,205 13,120 13,054
- ---------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 687,602 633,004 595,131
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 191,127 172,686 156,539
Purchased power --
Non-affiliates 56,082 40,080 33,872
Affiliates 51,057 31,007 36,037
Other 115,055 125,291 109,993
Maintenance 52,750 47,085 50,404
Depreciation and amortization 50,275 49,206 47,450
Taxes other than income taxes 48,686 47,893 45,965
- ---------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 565,032 513,248 480,260
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Income 122,570 119,756 114,871
Other Income (Expense):
Interest income 347 189 863
Other, net (647) 1,675 2,498
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 122,270 121,620 118,232
- ---------------------------------------------------------------------------------------------------------------------------------
Interest Expense and Other:
Interest expense, net 28,101 27,969 23,746
Distributions on preferred securities of subsidiary 2,712 2,712 2,712
- ---------------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 30,813 30,681 26,458
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 91,457 90,939 91,774
Income taxes 34,356 34,117 34,664
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income 57,101 56,822 57,110
Dividends on Preferred Stock 2,129 2,013 2,005
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 54,972 $ 54,809 $ 55,105
=================================================================================================================================
The accompanying notes are an integral part of these statements.
II-151
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
Mississippi Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 57,101 $ 56,822 $ 57,110
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 54,638 53,427 51,517
Deferred income taxes and investment tax credits, net 752 (4,143) 11,620
Other, net (1,747) 5,531 (12,175)
Changes in certain current assets and liabilities --
Receivables, net (3,231) (39,304) (5,486)
Fossil fuel stock 14,577 (9,379) (5,767)
Materials and supplies (1,056) (1,903) 717
Accounts payable 1,309 1,391 (389)
Other 2,952 14,206 (4,061)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 125,295 76,648 93,086
- -----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (81,211) (75,888) (68,231)
Other (9,153) 1,009 (324)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (90,364) (74,879) (68,555)
- -----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (1,500) 44,500 13,000
Proceeds --
Other long-term debt 100,000 59,400 103,520
Capital contributions from parent company 12,659 2,028 85
Retirements --
First mortgage bonds - - (75,000)
Other long-term debt (81,405) (50,456) (13,020)
Preferred stock - - (87)
Payment of preferred stock dividends (2,129) (2,013) (2,005)
Payment of common stock dividends (54,700) (56,100) (51,700)
Other (498) (282) (2,429)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (27,573) (2,923) (27,636)
- -----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 7,358 (1,154) (3,105)
Cash and Cash Equivalents at Beginning of Period 173 1,327 4,432
- -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 7,531 $ 173 $ 1,327
=============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $30,570 $25,486 $26,133
Income taxes (net of refunds) 28,418 39,729 26,847
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-152
BALANCE SHEETS
At December 31, 2000 and 1999
Mississippi Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
Assets 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 7,531 $ 173
Receivables --
Customer accounts receivable 72,064 61,274
Other accounts and notes receivable 21,843 23,490
Affiliated companies 10,071 16,097
Accumulated provision for uncollectible accounts (571) (697)
Fossil fuel stock, at average cost 11,220 25,797
Materials and supplies, at average cost 21,694 20,638
Other 8,320 10,013
- ----------------------------------------------------------------------------------------------------------------------------
Total current assets 152,172 156,785
- ----------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,665,879 1,601,399
Less accumulated provision for depreciation 652,891 626,841
- ----------------------------------------------------------------------------------------------------------------------------
1,012,988 974,558
Construction work in progress 60,951 68,721
- ----------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,073,939 1,043,279
- ----------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 2,268 1,389
- ----------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 13,860 21,557
Prepaid pension costs 6,724 2,488
Debt expense, being amortized 4,628 4,355
Premium on reacquired debt, being amortized 7,168 8,154
Other 14,312 13,129
- ----------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 46,692 49,683
- ----------------------------------------------------------------------------------------------------------------------------
Total Assets $1,275,071 $1,251,136
============================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-153
BALANCE SHEETS
At December 31, 2000 and 1999
Mississippi Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 20 $ 30,020
Notes payable 56,000 57,500
Accounts payable --
Affiliated 10,715 17,002
Other 48,146 43,105
Customer deposits 5,274 3,749
Taxes accrued --
Income taxes 8,769 6,865
Other 36,799 35,534
Interest accrued 4,482 6,733
Vacation pay accrued 5,701 5,218
Other 7,003 7,497
- ---------------------------------------------------------------------------------------------------------------------------
Total current liabilities 182,909 213,223
- ---------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 370,511 321,802
- ---------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 139,909 139,564
Deferred credits related to income taxes 25,603 34,765
Accumulated deferred investment tax credits 23,481 24,695
Employee benefits provisions 34,671 34,268
Workforce reduction plan 9,734 11,272
Other 16,546 12,770
- ---------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 249,944 257,334
- ---------------------------------------------------------------------------------------------------------------------------
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) 404,898 391,968
- ---------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,275,071 $1,251,136
===========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-154
STATEMENTS OF CAPITALIZATION
At December 31, 2000 and 1999
Mississippi Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
June 1, 2023 7.45% $ 35,000 $ 35,000
March 1, 2004 6.60% 35,000 35,000
December 1, 2025 6.875% 30,000 30,000
- ------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 100,000 100,000
- ------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.05% due May 1, 2003 35,000 35,000
6.75% due June 30, 2038 53,179 54,564
Adjustable rates (6.61% to 6.78% at 1/1/01)
due 2000-2002 100,000 80,000
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 188,179 169,564
- ------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.65% to 5.80% due 2007-2023 - 26,785
Variable rates (3.90% at 1/1/01)
due 2020-2025 - 10,600
Non-collateralized:
5.65% to 5.80% due 2007-2023 26,765
Variable rates (3.90% to 5.20% at 1/1/01)
due 2020-2028 56,820 46,220
- ------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 83,585 83,605
- ------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (1,233) (1,347)
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $23.8 million) 370,531 351,822
Less amount due within one year 20 30,020
- ------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $370,511 $321,802 43.9% 41.2%
- ------------------------------------------------------------------------------------------------------------------------------
II-155
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2000 and 1999
Mississippi Power Company 2000 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
(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 4.2 4.5
- -------------------------------------------------------------------------------------------------------------------------------
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 3.8 4.1
- -------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares in 2000 and 1999 37,691 37,691
Paid-in capital 194,161 181,502
Premium on preferred stock 326 326
Retained earnings 172,720 172,449
- -------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 404,898 391,968 48.1 50.2
- -------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $842,218 $780,579 100.0% 100.0%
===============================================================================================================================
The accompanying notes are an integral part of these statements.
II-156
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2000, 1999, and 1998
Mississippi Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1998 $37,691 $179,389 $327 $170,417 $387,824
Net income after dividends on preferred stock - - - 55,105 55,105
Capital contributions from parent company - 85 - - 85
Cash dividends on common stock - - - (51,700) (51,700)
Other - - (1) (82) (83)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 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
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-157
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2000 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 integrated Southeast utilities, a system
service company (SCS), Southern Communications Services (Southern LINC),
Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern
Nuclear), Mirant Corporation -- formerly Southern Energy, Inc. -- and other
direct and indirect subsidiaries. The integrated Southeast utilities -- Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company, and Savannah Electric and Power Company -- provide electric service in
four states. Contracts among the integrated Southeast utilities -- related to
jointly owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS
provides, at cost, specialized services to Southern Company and subsidiary
companies. Southern LINC provides digital wireless communications services to
the integrated Southeast utilities and also markets these services to the public
within the Southeast. Southern Company Energy Solutions develops new business
opportunities related to energy products and services. Southern Nuclear provides
services to Southern Company's nuclear power plants. Mirant acquires, develops,
builds, owns, and operates power production and delivery facilities and provides
a broad range of energy-related services to utilities and industrial companies
in selected countries around the world. Mirant businesses include independent
power projects, integrated utilities, a distribution company, and energy trading
and marketing businesses outside the southeastern United States.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both 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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension 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 $46.2
million, $45.5 million, and $43.9 million during 2000, 1999, and 1998,
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:
2000 1999
-------------------------
(in thousands)
Deferred income tax charges $ 13,860 $ 21,557
Vacation pay 5,701 5,218
Premium on reacquired debt 7,168 8,154
Property damage reserve (3,519) (3,082)
Deferred income tax credits (25,603) (34,765)
Other, net (505) (349)
- ----------------------------------------------------------------
Total $ (2,898) $ (3,267)
================================================================
II-158
NOTES (continued)
Mississippi Power Company 2000 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 and certain qualifying environmental costs. 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 2000 and
3.3 percent in 1999 and 1998. 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
The Company's 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, 2000 $371 $362
At December 31, 1999 $353 $334
Capital trust preferred
securities:
At December 31, 2000 $35 $34
At December 31, 1999 $35 $30
- --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on
either closing market price or closing price of comparable instruments.
11-159
NOTES (continued)
Mississippi Power Company 2000 Annual Report
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 2000, the Company
provided for such costs by charges to income of $3.5 million. In 1999 and 1998,
the Company provided for such costs by charges to income of $4.4 million and
$1.5 million, respectively. As of December 31, 2000, the accumulated provision
amounted to $3.5 million.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, pension plans that cover
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all these employees may
become eligible for such benefits when they retire. The Company funds trusts to
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 effects of these
changes will be to increase annual pension and postretirement benefits costs by
approximately $1.3 and $0.4 million, respectively. 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
--------------------------
2000 1999
- ---------------------------------------------------------------------
(in thousands)
Balance at beginning of year $139,930 $142,807
Service cost 4,272 4,415
Interest cost 10,196 9,377
Benefits paid (7,593) (8,050)
Actuarial gain and employee
transfers (1,419) (8,619)
- ---------------------------------------------------------------------
Balance at end of year $145,386 $139,930
=====================================================================
Plan Assets
--------------------------
2000 1999
- ---------------------------------------------------------------------
(in thousands)
Balance at beginning of year $221,487 $198,100
Actual return on plan assets 39,737 33,216
Benefits paid (7,593) (8,050)
Employee transfers 3,017 (1,779)
- ---------------------------------------------------------------------
Balance at end of year $256,648 $221,487
=====================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999
- ---------------------------------------------------------------------
(in thousands)
Funded status $111,263 $ 81,557
Unrecognized transition obligation (3,269) (3,814)
Unrecognized prior service cost 4,577 4,991
Unrecognized net gain (105,847) (80,246)
- ---------------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 6,724 $ 2,488
=====================================================================
II-160
NOTES (continued)
Mississippi Power Company 2000 Annual Report
Components of the plans' net periodic cost were as follows:
2000 1999 1998
- ------------------------------------------------------------------
(in thousands)
Service cost $ 4,272 $ 4,415 $ 3,848
Interest cost 10,196 9,377 9,613
Expected return on
plan assets (15,910) (14,681) (13,817)
Recognized net gain (2,663) (1,721) (1,956)
Net amortization (131) (131) (131)
- ------------------------------------------------------------------
Net pension income $ (4,236) $ (2,741) $(2,443)
==================================================================
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
----------------------------
2000 1999
- -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $45,390 $47,260
Service cost 830 982
Interest cost 3,309 3,105
Benefits paid (2,628) (2,256)
Actuarial gain and
employee transfers (1,949) (3,701)
- -----------------------------------------------------------------
Balance at end of year $44,952 $45,390
=================================================================
Plan Assets
----------------------------
2000 1999
- ------------------------------------------------------------------
(in thousands)
Balance at beginning of year $14,998 $12,779
Actual return on plan assets 2,511 1,818
Employer contributions 2,961 2,657
Benefits paid (2,627) (2,256)
- -----------------------------------------------------------------
Balance at end of year $17,843 $14,998
=================================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2000 1999
- ----------------------------------------------------------------------
(in thousands)
Funded status $(27,109) $(30,392)
Unrecognized transition obligation 4,275 4,621
Unrecognized net gain (6,632) (3,406)
Fourth quarter contributions 1,065 931
- ----------------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(28,401) $(28,246)
======================================================================
Components of the plans' net periodic cost were as follows:
2000 1999 1998
- --------------------------------------------------------------------
(in thousands)
Service cost $ 830 $ 981 $ 806
Interest cost 3,309 3,105 3,162
Expected return on
plan assets (1,235) (1,100) (989)
Net amortization 346 346 346
- --------------------------------------------------------------------
Net postretirement cost $ 3,250 $ 3,332 $3,325
====================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plans and postretirement benefits were:
2000 1999
---------------------------------------------------------------
Discount 7.50% 7.50%
Annual salary increase 5.00 5.00
Long-term return on plan assets 8.50 8.50
---------------------------------------------------------------
II-161
NOTES (continued)
Mississippi Power Company 2000 Annual Report
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 7.29
percent for 2000, decreasing gradually to 5.50 percent through the year 2005 and
remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2000 as follows:
1 Percent 1 Percent
Increase Decrease
- -----------------------------------------------------------------
(in thousands)
Benefit obligation $2,669 $2,396
Service and interest costs 242 215
- -----------------------------------------------------------------
Workforce Reduction Program
In 1997, approximately one hundred employees of the Company accepted the terms
of a workforce reduction plan. The cost incurred in connection with this
voluntary plan was approximately $18 million. The MPSC approved the deferral and
amortization of these program costs over a period not to exceed 60 months
beginning no later than July 1998. As of December 31, 1999, the cost was fully
amortized.
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 2000, 1999, and 1998 were $2.3
million, $2.2 million, and $2.1 million, respectively.
3. LITIGATION AND REGULATORY MATTERS
Environmental Litigation
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 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 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, 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 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. On January 12, 2001,
the EPA re-filed its claims against Alabama Power in federal district court in
Birmingham, Alabama. The EPA did not include SCS in the new complaint. 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 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 sharing rate adjustments based on the Company's ability to maintain low
rates for customers and on the Company's performance as measured by three
II-162
NOTES (continued)
Mississippi Power Company 2000 Annual Report
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. PEP will remain in effect until the MPSC modifies or terminates the
plan. There were no PEP retail revenue changes for 2000, 1999, or 1998.
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
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 2001 ECO Plan in
January and, if approved as filed, it 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,
Financing and 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 ratebase 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.
4. FINANCING AND COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, the costs of which
are currently estimated to total $62 million in 2001, $60 million in 2002, and
$69 million in 2003. 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.
Financing
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with
Escatawpa, that calls for the Company to design and construct, as agent for
Escatawpa, a 1,064 megawatt natural gas combined cycle facility. It is
anticipated that the total project will cost approximately $400 million, and
upon project completion in mid 2001, the Company intends to lease the facility
for an initial term of approximately 10 years. It is anticipated that the annual
lease payments will approximate $32 million during the initial term.
Bank Credit Arrangements
At December 31, 2000, the Company had total committed credit agreements with
banks for approximately $117 million. At year-end 2000, the unused portion of
these committed credit agreements was approximately $117 million. These credit
agreements expire at various dates in 2001. 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
II-163
NOTES (continued)
Mississippi Power Company 2000 Annual Report
agrees to pay commitment fees based on the unused portions of the commitments or
to maintain compensating balances with the banks. At December 31, 2000, the
Company had $56 million of short-term borrowings outstanding.
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.
Lease Agreements
In 1984, the Company and Entergy Corp. (formerly Gulf States Utilities) entered
into a forty-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 2000, use fees collected
under this agreement, net of related expenses, amounted to approximately $3
million each year, and are included within Other Income in the Statements of
Income.
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. In 1997, a third lease agreement for the
use of 360 railcars was also entered into for three years, with a monthly
renewal option for up to an additional nine months. All of these leases,
totaling 1,105 railcars, were for the transport of coal to Plant Daniel.
Gulf Power, as joint owner of Plant Daniel, is responsible for one half of
the lease cost. The Company's share (50%) of the leases, charged to fuel stock,
was $2.1 million in 2000, $2.8 million in 1999, and $2.8 million in 1998. The
Company's annual lease payments for 2001 through 2005 will average approximately
$2.0 million and after 2005, lease payments total in aggregate approximately $14
million.
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.
Total estimated obligations at December 31, 2000 were as follows:
Year Fuel
- ---- ----
(in millions)
2001 $ 294
2002 332
2003 313
2004 137
2005 95
2006 - 2024 131
Total commitments $1,302
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, 2000, 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% $63,346 $32,762
Daniel
Units 1 and 2 1,000 50% $230,853 $115,472
-----------------------------------------------------------------------
The Company's share of plant operating expenses is included in the
corresponding operating expenses in the Statements of Income.
II-164
NOTES (continued)
Mississippi Power Company 2000 Annual Report
6. LONG-TERM CAPACITY SALES AND LEASE
AGREEMENTS
The Company and the other utility affiliates 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.
During 2000, the Company entered into a 10 year capacity lease that begins
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.
7. INCOME TAXES
At December 31, 2000, the tax-related regulatory assets and liabilities were $14
million and $26 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:
2000 1999 1998
----------------------------------
(in thousands)
Total provision for
income taxes
Federal --
Current $28,934 $33,379 $20,500
Deferred 622 (3,973) 9,442
-----------------------------------------------------------------
29,556 29,406 29,942
-----------------------------------------------------------------
State --
Current 4,670 4,881 2,544
Deferred 130 (170) 2,178
-----------------------------------------------------------------
4,800 4,711 4,722
-----------------------------------------------------------------
Total $34,356 $34,117 $34,664
=================================================================
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:
2000 1999
-----------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $151,278 $154,698
Basis differences 8,559 8,967
Other 24,136 23,108
---------------------------------------------------------------
Total 183,973 186,773
---------------------------------------------------------------
Deferred tax assets:
Other property
basis differences 17,147 21,003
Pension and
other benefits 9,528 9,608
Property insurance 3,558 3,419
Unbilled fuel 5,727 4,846
Other 9,669 11,071
---------------------------------------------------------------
Total 45,629 49,947
---------------------------------------------------------------
Net deferred tax
liabilities 138,344 136,826
Portion included in
current assets, net 1,565 2,738
---------------------------------------------------------------
Accumulated deferred
income taxes in the
Balance Sheets $139,909 $139,564
===============================================================
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 2000, 1999, and 1998. At December 31, 2000, 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:
2000 1999 1998
----------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax, net of
federal deduction 3.4 3.4 3.3
Non-deductible book
depreciation .6 .7 .5
Other (1.5) (1.6) (1.0)
------------------------------------------------------------------
Effective income tax rate 37.5% 37.5% 37.8%
==================================================================
II-165
NOTES (continued)
Mississippi Power Company 2000 Annual Report
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis.
8. COMPANY OBLIGATED MANDATORILY
REDEEMABLE 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 Trusts' 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.
9. 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:
2000 1999
---------------------
(in thousands)
Bond improvement fund requirement $1,000 $1,000
Less: Portion to be satisfied by
certifying property additions 1,000 1,000
---------------------------------------------------------------
Cash sinking fund requirement - -
Current portion of other long-term debt - 30,000
Pollution control bond cash
sinking fund requirements 20 20
---------------------------------------------------------------
Total $20 $30,020
===============================================================
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.
10. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's first mortgage bond indenture and the corporate charter contain
various common stock dividend restrictions. At December 31, 2000, 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.
11. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 2000 and 1999 are as follows:
Net Income
After Dividends
Operating Operating On Preferred
Quarter Ended Revenues Income Stock
- --------------------------------------------------------------------
(in thousands)
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
March 1999 $122,435 $18,122 $7,193
June 1999 158,590 31,289 14,953
September 1999 201,594 51,609 27,313
December 1999 150,385 18,736 5,350
- --------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes.
II-166
SELECTED FINANCIAL AND OPERATING DATA 1996-2000
Mississippi Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)* $687,602 $633,004 $595,131 $543,588 $544,029
Net Income after Dividends
on Preferred Stock (in thousands) $54,972 $54,809 $55,105 $54,010 $52,723
Cash Dividends
on Common Stock (in thousands) $54,700 $56,100 $51,700 $49,400 $43,900
Return on Average Common Equity (percent) 13.80 14.00 14.15 14.00 13.90
Total Assets (in thousands) $1,275,071 $1,251,136 $1,189,605 $1,166,829 $1,142,327
Gross Property Additions (in thousands) $81,211 $75,888 $68,231 $55,375 $61,314
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $404,898 $391,968 $391,231 $387,824 $383,734
Preferred stock 31,809 31,809 31,809 31,896 74,414
Company obligated mandatorily
redeemable preferred securities 35,000 35,000 35,000 35,000 -
Long-term debt 370,511 321,802 292,744 291,665 326,379
- -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $842,218 $780,579 $750,784 $746,385 $784,527
=============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 48.1 50.2 52.1 52.0 48.9
Preferred stock 3.8 4.1 4.2 4.3 9.5
Company obligated mandatorily
redeemable preferred securities 4.2 4.5 4.7 4.7 -
Long-term debt 43.9 41.2 39.0 39.0 41.6
- -----------------------------------------------------------------------------------------------------------------------------
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+ AA- AA- AA- A+
Fitch AA- AA- AA- AA- AA-
Preferred Stock -
Moody's a1 a1 a1 a1 a1
Standard and Poor's BBB+ A- A A A
Fitch A A A+ A+ A+
=============================================================================================================================
Customers (year-end):
Residential 158,253 157,592 156,530 156,650 154,630
Commercial 32,372 31,837 31,319 31,667 30,366
Industrial 517 546 587 642 639
Other 206 202 200 200 200
- -----------------------------------------------------------------------------------------------------------------------------
Total 191,348 190,177 188,636 189,159 185,835
=============================================================================================================================
Employees (year-end): 1,319 1,328 1,230 1,245 1,363
- -----------------------------------------------------------------------------------------------------------------------------
* 1999 data includes the true-up of the unbilled revenue estimates.
II-167
SELECTED FINANCIAL AND OPERATING DATA 1996-2000 (continued)
Mississippi Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)*:
Residential $ 170,729 $159,945 $157,642 $138,608 $137,055
Commercial 163,552 153,936 145,677 134,208 131,734
Industrial 159,705 151,244 135,039 140,233 141,324
Other 4,565 4,309 4,209 4,193 4,013
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 498,551 469,434 442,567 417,242 414,126
Sales for resale - non-affiliates 145,931 131,004 121,225 105,141 99,596
Sales for resale - affiliates 27,915 19,446 18,285 10,143 21,830
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 672,397 619,884 582,077 532,526 535,552
Other revenues 15,205 13,120 13,054 11,062 8,477
- ----------------------------------------------------------------------------------------------------------------------------------
Total $687,602 $633,004 $595,131 $543,588 $544,029
==================================================================================================================================
Kilowatt-Hour Sales (in thousands)*:
Residential 2,286,143 2,248,255 2,248,915 2,039,042 2,079,611
Commercial 2,883,197 2,847,342 2,623,276 2,407,520 2,315,860
Industrial 4,376,171 4,407,445 3,729,166 3,981,875 3,960,243
Other 41,153 40,091 39,772 40,508 39,297
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 9,586,664 9,543,133 8,641,129 8,468,945 8,395,011
Sales for resale - non-affiliates 3,674,621 3,256,175 3,157,837 2,895,182 2,726,993
Sales for resale - affiliates 452,611 539,939 552,142 478,884 693,510
- ----------------------------------------------------------------------------------------------------------------------------------
Total 13,713,896 13,339,247 12,351,108 11,843,011 11,815,514
==================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents)*:
Residential 7.47 7.11 7.01 6.80 6.59
Commercial 5.67 5.41 5.55 5.57 5.69
Industrial 3.65 3.43 3.62 3.52 3.57
Total retail 5.20 4.92 5.12 4.93 4.93
Sales for resale 4.21 3.96 3.76 3.42 3.55
Total sales 4.90 4.65 4.71 4.50 4.53
Residential Average Annual
Kilowatt-Hour Use Per Customer * 14,445 14,301 14,376 13,132 13,469
Residential Average Annual
Revenue Per Customer * $1,078.76 $1,017.42 $1,007.68 $892.68 $887.66
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,086 2,086 2,086 2,086 2,086
Maximum Peak-Hour Demand (megawatts):
Winter 2,305 2,125 1,740 1,922 2,030
Summer 2,593 2,439 2,339 2,209 2,117
Annual Load Factor (percent) 59.3 59.6 58.0 59.1 60.7
Plant Availability Fossil-Steam (percent): 92.6 91.0 90.0 92.4 91.8
- ----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 67.8 69.4 66.5 70.5 70.4
Oil and gas 13.5 15.9 14.5 12.5 12.0
Purchased power -
From non-affiliates 7.7 6.2 8.0 3.0 6.5
From affiliates 11.0 8.5 11.0 14.0 11.1
- ----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==================================================================================================================================
* 1999 data includes the true-up of the unbilled revenue estimates.
II-168
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-169
MANAGEMENT'S REPORT
Savannah Electric and Power Company 2000 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/G. Edison Holland, Jr. /s/K. R. Willis
G. Edison Holland, Jr. K. R. Willis
President Vice President,
and Chief Executive Officer Treasurer, Chief Financial Officer
and Assistant Secretary
11-170
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, 2000 and 1999, 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, 2000. 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-179 through II-193)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 2000 and
1999, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2000, in conformity with
accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP
Arthur Andersen LLP
Atlanta, Georgia
February 28, 2001
II-171
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Savannah Electric and Power Company 2000 Annual Report
RESULTS OF OPERATIONS
- --------------------
Earnings
Savannah Electric and Power Company's net income after dividends on preferred
stock for 2000 totaled $23.0 million, representing no significant change from
the prior year.
In 1999, earnings were $23.1 million, representing a $0.6 million, or 2.4
percent decrease from the prior year. This was principally due to lower
non-operating revenues.
Revenues
Total operating revenues for 2000 were $295.7 million, reflecting a 17.5 percent
increase when compared to 1999. The following table summarizes the factors
affecting operating revenues for the past two years:
Increase (Decrease)
From Prior Year
-------------------------
Amount
2000 2000 1999
--------------------------------------
(in thousands)
Retail --
Base Revenues $161,807 $ 9,272 $ 376
Fuel cost recovery
and other 120,815 31,085 (438)
-----------------------------------------------------------------
Total retail 282,622 40,357 (62)
-----------------------------------------------------------------
Sales for resale --
Non-affiliates 4,748 1,353 (1,153)
Affiliates 4,974 823 1,135
-----------------------------------------------------------------
Total sales for resale 9,722 2,176 (18)
-----------------------------------------------------------------
Other operating revenues 3,374 1,591 (2,781)
-----------------------------------------------------------------
Total operating revenues $295,718 $44,124 $(2,861)
=================================================================
Percent change 17.5% (1.1)%
-----------------------------------------------------------------
Retail revenues increased 16.7 percent or $40.4 million in 2000 as compared
to 1999. The primary contributors to the increase were continued growth in the
Company's service territory, the positive impact of weather on energy sales, and
an increase in fuel revenues.
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. The Company currently plans to make a filing with
the Georgia Public Service Commission (GPSC) in early 2001 to establish a new
fuel rate in order to better reflect current fuel cost and to collect the
current under-recovered balance.
Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. Revenues from these sales
were not material to the financial statements.
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 2000 and the percent change by year were as
follows:
KWH Percent Change
------------- -------------------
2000 2000 1999
------------- -------------------
(in millions)
Residential 1,671 5.8% 2.6%
Commercial 1,369 6.3 4.2
Industrial 800 12.2 (20.7)
Other 137 2.5 1.1
-------
Total retail 3,977 7.1 (2.5)
Sales for resale --
Non-affiliates 77 50.3 (3.3)
Affiliates 89 15.1 31.8
--------
Total 4,143 7.8% (2.0)%
===========================================================
Total retail energy sales in 2000 reflected increases in all customer
classes. Industrial energy sales increased 12.2 percent reflecting the
re-opening of an industrial facility under new ownership. Residential and
commercial sales also increased reflecting weather related demand and customer
growth.
In 1999, total retail energy sales were down by 2.5 percent from the prior
year reflecting reduced energy sales of 20.7 percent to industrial customers due
to the shut-down of one industrial customer's facilities in late 1998 and
II-172
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2000 Annual Report
completed construction of a steam turbine unit by another industrial customer.
These reductions were partially mitigated by increased energy sales of 2.6
percent and 4.2 percent to residential and commercial customers, respectively.
Expenses
Total operating expenses for 2000 were $245.0 million, an increase of $42.0
million from the prior year due primarily to increases in purchased power from
both affiliates and non-affiliates and generation fuel expense. The increase in
fuel expense is attributable to an increase in generation and higher fuel costs.
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.
In 1999, total operating expenses were $203.0 million reflecting a slight
increase of $1.4 million from the prior year. This increase was due primarily to
increases in purchased power from non-affiliates and depreciation and
amortization. Purchased power from non-affiliates increased due principally to
higher demand for energy and increased costs associated with these power
purchases. Depreciation and amortization increased reflecting additional
depreciation charges related to the GPSC's 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:
2000 1999 1998
--------------------------
Total energy supply
(millions of KWHs) 4,286 4,039 4,182
Sources of energy supply
(percent) --
Coal 52 45 42
Oil 2 2 1
Gas 5 10 12
Purchased Power 41 43 45
Total average cost of
energy supply (cents) 3.09 2.44 2.35
- -----------------------------------------------------------------
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
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.
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).
II-173
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2000 Annual Report
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.
Georgia Power 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 capacity from these units to serve its retail customers
for approximately seven years.
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. The Company is positioning the business to meet the
challenge of this major change in the traditional practice of selling
electricity.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While 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
transmission pricing and recovery of costs. The GPSC continues its assessment of
the range of potential stranded costs. The inability of the Company to recover
its investments, including the regulatory assets described in Note 1 to the
financial statements, could have a material adverse effect on the financial
condition and results of operation. The Company is attempting to minimize or
reduce its cost exposure.
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.
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 issued a four-year accounting order settling its review of the
Company's earnings. See Note 3 to the financial statements for additional
information.
On December 20, 1999, FERC issued its final rule on Regional Transmission
Organizations (RTOs). The order encouraged utilities owning transmission systems
to form RTOs on a voluntary basis. After participating in regional conferences
with customers and other members of the public to discuss the formation of RTOs,
utilities were required to make a filing. On October 16, 2000, Southern Company
and its integrated utility subsidiaries, including the Company, filed with FERC
a proposal for the creation of an RTO. The proposal is for the formation of a
for-profit company that would have control of the bulk power transmission system
of Southern Company and any other participating utilities. Participants would
have the option to maintain their ownership, divest, sell, or lease their assets
to the proposed RTO. If the FERC accepts the proposal as filed, the creation of
an RTO is not expected to have a material impact on Southern Company's financial
statements. The outcome of this matter cannot now be determined.
The Energy Act amended the Public Utility Holding Company Act of 1935
(PUCHA) to allow holding companies to form exempt wholesale generators to sell
power largely free of regulation under PUCHA. These entities are able to own and
II-174
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2000 Annual Report
operate power generating facilities and sell power to affiliates--under certain
restrictions.
Southern Company is aggressively working to maintain and expand its share
of wholesale sales in the southeastern power markets. In January 2001, Southern
Company announced formation of a new subsidiary--Southern Power Company. The new
subsidiary will own, manage, and finance wholesale generating assets in the
Southeast. Energy from its assets will be marketed to wholesale customers under
the Southern Company name.
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."
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 Standard
In June 2000, FASB issued Statement No. 138, an amendment of Statement No.
133, Accounting for Derivative Instruments and Hedging Activities. Statement No.
133, as amended, establishes accounting and reporting standards for derivative
instruments and for hedging activities. Statement No. 133 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 Company enters into commodity related forward contracts to limit
exposure to changing prices on electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales meet the
definition of a derivative under Statement No. 133. In many cases, these
transactions meet the normal purchase and sale exception and the related
contracts will continue to be accounted for under the accrual method. Certain
of these instruments qualify as cash flow hedges resulting in the deferral of
related gains and losses in other comprehensive income until the hedged
transactions occur. Any ineffectiveness will be recognized currently in net
income. However, others will be required to be marked to market through current
period income.
The Company adopted Statement No. 133 effective January 1, 2001. The impact
on net income was immaterial to the Company. The application of the new rules is
still evolving and further guidance from FASB is expected, which could further
impact the Company's financial statements. Also, as wholesale energy markets
mature, future transactions could result in more volatility in net income and
comprehensive income.
FINANCIAL CONDITION
- ------------------
Overview
The principal change in the Company's financial condition in 2000 was the
addition of $27.3 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.
Exposure to Market Risks
Due to cost-based regulation, the Company has limited exposure to market
volatility in interest rate, 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, 2000,
exposure from these activities was not material to the Company's financial
statements. Also, based on the Company's overall interest rate exposure at
December 31, 2000, a near-term 100 basis point change in interest rates would
not materially affect the financial statements.
II-175
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2000 Annual Report
Capital Structure
As of December 31, 2000, the Company's capital structure consisted of 52.7
percent common stockholders' equity, 12.1 percent trust preferred securities,
and 35.2 percent long-term debt, excluding amounts due within one year. The
Company's long-term financial objective for capitalization ratios is to maintain
a capital structure of common stockholders' equity at 48 percent, preferred
securities at 10 percent and debt at 42 percent.
Maturities and retirements of long-term debt were $0.4 million in 2000,
$16.2 million in 1999, and $30.4 million in 1998.
Included in the 1999 maturities and retirements is the purchase by the
Company of all $15 million outstanding of its 7 7/8% Series First Mortgage Bonds
due May 1, 2025.
The composite interest rates and dividend rates for the years 1998 through
2000 as of year-end were as follows:
2000 1999 1998
-------------------------------
Composite interest rates
on long-term debt 6.6% 6.4% 6.5%
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
$95.9 million ($32.5 million in 2001, $31.5 million in 2002, and $31.9 million
in 2003). Actual construction costs may vary from this estimate because of
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
$51.8 million will be needed by the end of 2003 for maturities of long-term debt
and present sinking fund requirements.
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 integrated
Southeast utilities 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 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
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 the system service company's motion to
dismiss on the grounds that it neither owned nor operated the generating units
involved in the proceedings. On January 12, 2001, the EPA re-filed its claims
against Alabama Power in federal district court in Birmingham, Alabama. The EPA
did not include the system service company in the new complaint. Southern
Company believes that its integrated utilities 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
II-176
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2000 Annual Report
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 and some 50 generating units of Southern Company were
brought into compliance with Phase I requirements.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
The construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $2 million for Savannah Electric.
Phase II sulfur dioxide compliance was required in 2000. Southern Company
used emission allowances and fuel switching to comply with Phase II
requirements. No significant dollars for Phase II compliance have been spent by
Savannah Electric.
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 recently dismissed certain challenges but 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
will address other legal challenges to these standards in mid-2001. If the
standards are eventually upheld, implementation could be required by 2007 to
2010.
In September 1998, the EPA issued the final regional nitrogen oxide
reduction rules to the states for implementation. Compliance is required by May
31, 2004. The final rule affects 21 states, including Georgia. This rule remains
involved in litigation in the federal courts.
In December 2000, the EPA completed its utility studies 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 (MACT) provisions of the Clean Air Act. This determination is
being challenged in the courts. 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 BART rules is probable in the near
future.
Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide, sulfur dioxide, 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. Reviews by the new administration in Washington, D.C.
add to the uncertainties associated with BART guidance and the MACT
determination for mercury and other HAPS.
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; 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.
II-177
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2000 Annual Report
The Company conducts studies to determine the extent of any required cleanup
costs 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, 2000, the Company had $50.1 million of unused 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.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulation, 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.
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," "expects," "plans," "anticipates,"
"believes," "estimates," "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 against the Company;
the extent and timing of the entry of additional competition in the markets of
the Company; potential business strategies, including acquisitions or
dispositions of assets or businesses, which cannot be assured to be completed or
beneficial; internal restructuring or other restructuring options that may be
pursued by the Company; state and federal rate regulation in the United States;
political, legal and economic conditions and developments in the United States;
financial market conditions and the results of financing efforts; the impact of
fluctuations in commodity prices, interest rates and customer demand; 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 SEC.
II-178
STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
Savannah Electric and Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $282,622 $242,265 $242,327
Sales for resale --
Non-affiliates 4,748 3,395 4,548
Affiliates 4,974 4,151 3,016
Other revenues 3,374 1,783 4,564
- ---------------------------------------------------------------------------------------------------------------
Total operating revenues 295,718 251,594 254,455
- ---------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 57,177 50,530 53,021
Purchased power --
Non-affiliates 25,229 14,398 9,460
Affiliates 50,111 33,398 35,687
Other 54,829 51,802 50,321
Maintenance 19,334 16,333 18,711
Depreciation and amortization (Note 3) 25,240 23,841 22,032
Taxes other than income taxes 13,116 12,690 12,342
- ---------------------------------------------------------------------------------------------------------------
Total operating expenses 245,036 202,992 201,574
- ---------------------------------------------------------------------------------------------------------------
Operating Income 50,682 48,602 52,881
Other Income (Expense):
Interest income 252 169 384
Other, net 1,086 798 (432)
- ---------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 52,020 49,569 52,833
- ---------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net 12,737 11,938 11,855
Distributions on preferred securities of subsidiary 2,740 2,740 167
- ---------------------------------------------------------------------------------------------------------------
Total interest and other, net 15,477 14,678 12,022
- ---------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 36,543 34,891 40,811
Income taxes (Note 5) 13,574 11,808 15,101
- ---------------------------------------------------------------------------------------------------------------
Net Income 22,969 23,083 25,710
Dividends on Preferred Stock - - 2,066
- ---------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 22,969 $ 23,083 $ 23,644
===============================================================================================================
The accompanying notes are an integral part of these statements.
II-179
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
Savannah Electric and Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $22,969 $23,083 $25,710
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 26,639 25,454 23,531
Deferred income taxes and investment tax credits, net 728 (3,353) 7,011
Other, net 3,835 (47) (89)
Changes in certain current assets and liabilities --
Receivables, net (23,260) (5,999) (9,875)
Fossil fuel stock (31) (2,125) 221
Materials and supplies (542) (1,906) 484
Accounts payable 8,881 1,133 470
Other (4,674) 1,731 (4,859)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 34,545 37,971 42,604
- ------------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (27,290) (29,833) (18,071)
Other (1,835) (1,715) 1,617
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (29,125) (31,548) (16,454)
- ------------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase in notes payable, net 11,100 34,300 -
Proceeds --
Other long-term debt - - 30,000
Preferred securities - - 40,000
Capital contributions from parent company 1,478 1,099 -
Retirements --
First mortgage bonds - (15,800) (30,000)
Other long-term debt (251) (481) (478)
Preferred stock - - (35,000)
Payment of preferred stock dividends - - (2,556)
Payment of common stock dividends (24,300) (25,200) (23,500)
Other - 250 (4,798)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (11,973) (5,832) (26,332)
- ------------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (6,553) 591 (182)
Cash and Cash Equivalents at Beginning of Period 6,553 5,962 6,144
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ - $ 6,553 $ 5,962
====================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $13,329 $14,212 $12,198
Income taxes (net of refunds) 19,939 12,647 9,666
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-180
BALANCE SHEETS
At December 31, 2000 and 1999
Savannah Electric and Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------
Assets 2000 1999
- -----------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ - $ 6,553
Receivables --
Customer accounts receivable 28,189 20,752
Unrecovered retail fuel clause revenue 39,632 21,089
Other accounts and notes receivable 1,412 3,505
Affiliated companies 738 1,195
Accumulated provision for uncollectible accounts (407) (237)
Fossil fuel stock, at average cost 7,140 7,109
Materials and supplies, at average cost 8,944 8,402
Prepaid taxes 8,651 2,434
Other 377 435
- -----------------------------------------------------------------------------------------------------------------
Total current assets 94,676 71,237
- -----------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Note 7) 829,270 804,096
Less accumulated provision for depreciation 382,030 360,639
- -----------------------------------------------------------------------------------------------------------------
447,240 443,457
Construction work in progress 6,782 6,561
- -----------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 454,022 450,018
- -----------------------------------------------------------------------------------------------------------------
Other Property and Investments 2,066 1,506
- -----------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 5) 12,404 16,063
Cash surrender value of life insurance for deferred compensation plans 17,954 16,305
Prepaid pension costs (Note 2) - 1,201
Debt expense, being amortized 3,003 3,155
Premium on reacquired debt, being amortized 7,575 8,385
Other 2,527 2,348
- -----------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 43,463 47,457
- -----------------------------------------------------------------------------------------------------------------
Total Assets $594,227 $570,218
=================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-181
BALANCE SHEETS
At December 31, 2000 and 1999
Savannah Electric and Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2000 1999
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 7) $ 30,698 $ 704
Notes payable 45,400 34,300
Accounts payable --
Affiliated 16,153 4,632
Other 7,738 11,118
Customer deposits 5,696 5,426
Taxes accrued --
Income taxes 3,450 3,046
Other 1,435 3,013
Interest accrued 4,541 3,237
Vacation pay accrued 2,276 2,142
Other 7,973 5,742
- --------------------------------------------------------------------------------------------------------------------------
Total current liabilities 125,360 73,360
- --------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 116,902 147,147
- --------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 5) 79,756 80,318
Deferred credits related to income taxes (Note 5) 16,038 19,687
Accumulated deferred investment tax credits (Note 5) 10,616 11,280
Deferred compensation plans 11,968 10,624
Employee benefits provisions (Note 2) 8,127 7,805
Other 10,466 5,150
- --------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 136,971 134,864
- --------------------------------------------------------------------------------------------------------------------------
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) 174,994 174,847
- --------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $594,227 $570,218
==========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-182
STATEMENTS OF CAPITALIZATION
At December 31, 2000 and 1999
Savannah Electric and Power Company 2000 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2000 1999 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt (Note 7):
First mortgage bonds --
Maturity Interest Rates
-------- --------------
July 1, 2003 6.375% $ 20,000 $ 20,000
May 1, 2006 6.90% 20,000 20,000
July 1, 2023 7.40% 24,200 24,200
- -----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 64,200 64,200
- -----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.88% due June 1, 2001 10,000 10,000
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 20,000
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 60,000 60,000
- -----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Non-collateralized:
Variable rates (5.10% at 1/1/01)
due 2016-2037 17,955 17,955
- -----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 17,955 17,955
- -----------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 5,445 5,696
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $9.8 million) 147,600 147,851
Less amount due within one year (Note 7) 30,698 704
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 116,902 147,147 35.2% 40.7%
- -----------------------------------------------------------------------------------------------------------------------------
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 12.1 11.0
- -----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (Note 8):
Common stock, par value $5 per share --
Authorized - 16,000,000 shares
Outstanding - 10,844,635 shares in 2000 and 1999
Par value 54,223 54,223
Paid-in capital 11,265 9,787
Retained earnings 109,506 110,837
- -----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 174,994 174,847 52.7 48.3
- -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $331,896 $361,994 100.0% 100.0%
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-183
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2000, 1999, and 1998
Savannah Electric and Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Common Paid-In Retained
Stock Capital Earnings Total
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1998 $54,223 $8,688 $112,720 $175,631
Net income after dividends on preferred stock - - 23,644 23,644
Cash dividends on common stock - - (23,500) (23,500)
Other - - 90 90
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 54,223 8,688 112,954 175,865
Net income after dividends on preferred stock - - 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 after dividends on preferred stock - - 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 (Note 8) $54,223 $11,265 $109,506 $174,994
=================================================================================================================================
The accompanying notes are an integral part of these statements.
II-184
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2000 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 integrated Southeast
utilities, a system service company (SCS), Southern Communications Services
(Southern LINC), Southern Company Energy Solutions, Southern Nuclear Operating
Company (Southern Nuclear), Mirant Corporation--formerly Southern Energy,
Inc.--and other direct and indirect subsidiaries. The integrated Southeast
utilities provide electric service in four states. Contracts among the
integrated Southeast utilities--related to jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power--are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. SCS provides, at cost, specialized services
to Southern Company and subsidiary companies. Southern LINC provides digital
wireless communications services to the integrated Southeast utilities and also
markets these services to the public within the Southeast. Southern Company
Energy Solutions develops new business opportunities related to energy products
and services. Southern Nuclear provides services to Southern Company's nuclear
power plants. Mirant acquires, develops, builds, owns and operates power
production and delivery facilities, and provides a broad range of energy-related
services to utilities and industrial companies in selected countries around the
world. Mirant businesses include independent power projects, integrated
utilities, a distribution company, and energy trading and marketing businesses
outside the southeastern United States.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other administrative services with respect to business and
operations and power pool operations. Costs for these services amounted to $15.1
million, $16.0 million, and $15.3 million during 2000, 1999, and 1998,
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:
2000 1999
--------------------------
(in thousands)
Deferred income tax charges $12,404 $ 16,063
Premium on reacquired debt 7,575 8,385
Deferred income tax credits (16,038) (19,687)
Storm damage reserves (2,733) (1,392)
Accelerated depreciation (5,500) (3,000)
- ---------------------------------------------------------------
Total $(4,292) $ 369
===============================================================
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.
II-185
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
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.
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 2000, the GPSC approved an increase of slightly over one-third of a cent
per kilowatt hour in the Company's fuel cost recovery rate. An increase of
slightly over three-tenths of a cent per kilowatt-hour was approved in 1999.
The Company currently plans to make a filing with the GPSC in early 2001 to
establish a new fuel rate in order to better reflect current fuel costs and to
collect the current under-recovered balance.
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 2000 and
1999, and 2.9 percent in 1998. 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 1998, 1999 and 2000, the Company recorded accelerated
depreciation of $1.0 million, $2.0 million and $2.5 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, which is included in the consolidated federal income tax return
filed by 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.
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 6.87 percent in 2000, 6.26 percent in 1999 and 8.00 percent in 1998.
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 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
II-186
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Financial Instruments
The Company's 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, 2000 $142 $140
At December 31, 1999 $142 $136
Trust preferred securities:
At December 31, 2000 $40 $36
At December 31, 1999 $40 $31
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. Substantially all these employees
may become eligible for such benefits when they retire. The Company funds trusts
to the extent required by the GPSC. 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. The effects of these changes will be to increase annual
pension and postretirement benefits costs by approximately $0.5 million and $0.3
million, respectively.
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
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $59,961 $59,207
Service cost 1,742 1,746
Interest cost 4,380 3,893
Benefits paid (3,210) (3,414)
Actuarial (gain) loss and
employee transfers 1,802 (1,856)
Amendments 219 385
- ---------------------------------------------------------------
Balance at end of year $64,894 $59,961
===============================================================
Plan Assets
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $54,480 $49,630
Actual return on plan assets 10,493 8,168
Benefits paid (3,210) (3,414)
Employee transfers 117 96
- ---------------------------------------------------------------
Balance at end of year $61,880 $54,480
===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
2000 1999
- ---------------------------------------------------------------
(in thousands)
Funded status $(3,014) $(5,481)
Unrecognized transition
obligation 89 178
Unrecognized prior service 2,929 2,996
cost
Unrecognized net loss (gain) (1,127) 3,508
- ---------------------------------------------------------------
(Accrued liability) prepaid
asset recognized in the
Balance Sheets $(1,123) $1,201
===============================================================
II-187
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
Components of the plans' net periodic cost were as follows:
2000 1999 1998
- -----------------------------------------------------------------
(in thousands)
Service cost $1,742 $1,746 $1,495
Interest cost 4,380 3,893 3,806
Expected return on plan
assets (4,174) (4,063) (3,992)
Recognized net loss - 152 2
Net amortization 376 352 334
- -----------------------------------------------------------------
Net pension cost $2,324 $2,080 $1,645
=================================================================
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
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $22,904 $23,556
Service cost 376 404
Interest cost 1,865 1,549
Benefits paid (963) (756)
Actuarial gain and
employee transfers (1,367) (1,849)
Amendments 3,309 -
- ---------------------------------------------------------------
Balance at end of year $26,124 $22,904
===============================================================
Plan Assets
---------------------------
2000 1999
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $5,254 $3,803
Actual return on plan assets 606 476
Employer contributions 2,013 1,731
Benefits paid (963) (756)
- ---------------------------------------------------------------
Balance at end of year $6,910 $5,254
===============================================================
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
2000 1999
- ---------------------------------------------------------------
(in thousands)
Funded status $(19,214) $(17,650)
Unrecognized transition
obligation 5,925 6,419
Unamortized prior service cost 3,185 -
Unrecognized net loss 1,701 3,311
Fourth quarter contributions 1,493 1,336
- ---------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $ (6,910) $ (6,584)
===============================================================
Components of the postretirement plans' net periodic cost
were as follows:
2000 1999 1998
- ----------------------------------------------------------------
(in thousands)
Service cost $ 376 $ 404 $ 348
Interest cost 1,865 1,549 1,528
Expected return on plan assets (429) (345) (276)
Recognized net loss 66 152 104
Net amortization 618 494 494
- ----------------------------------------------------------------
Net postretirement cost $2,496 $2,254 $2,198
================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
2000 1999
- ---------------------------------------------------------------
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 7.29
percent for 2000, decreasing gradually to 5.50 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2000 as follows:
II-188
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in thousands)
Benefit obligation $1,417 $1,598
Service and interest costs 110 140
===============================================================
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 2000, 1999, and 1998 were $0.9
million, $0.9 million, and $0.8 million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
Environmental Litigation
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
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, 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 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 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 the system service company's motion to dismiss on the grounds that
it neither owned nor operated the generating units involved in the proceedings.
On January 12, 2001, the EPA re-filed its claims against Alabama Power in
federal district court in Birmingham, Alabama. The EPA did not include the
system service company in the new complaint. Southern Company believes that its
integrated utilities 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
II-189
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
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 in both 2000 and 1999 and
$0.75 million in 1998. 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.
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated
to total $32.5 million in 2001, $31.5 million in 2002, and $31.9 million in
2003. 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.
To the extent possible, the Company's construction program is expected to
be financed from internal sources and from the issuance of additional long-term
debt and capital contributions from Southern Company.
The amounts of long-term debt and trust preferred securities that can be
issued in the future will be contingent on market conditions, the maintenance of
adequate earnings levels, regulatory authorizations, and other factors.
Bank Credit Arrangements
At the end of 2000, unused credit arrangements with four banks totaled $50.1
million and expire at various times during 2001.
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.
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 $10 million of bank debt is secured by a portion of the Plant Kraft
property and a second lien for $34 million in bank notes is secured by a portion
of the Plant McIntosh property.
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 $44 million and $8 million for 2001 and 2002, respectively.
The company has entered into various long-term commitments for the purchase
of electricity. Estimated total long-term obligations at December 31, 2000 were
as follows:
Year Commitments
- ---- -------------
(in thousands)
2001 $ 0
2002 9,627
2003 13,245
2004 13,261
2005 13,277
2006 and beyond 53,283
- ---------------------------------------------------------------
Total commitments $102,693
===============================================================
II-190
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
Operating Leases
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $0.4 million for 2000, $0.5 million for 1999, and $1.1
million for 1998.
At December 31, 2000, estimated future minimum lease payments for
noncancelable operating leases were as follows:
Rental
Commitments
--------------------
(in thousands)
2001 $433
2002 433
2003 433
2004 433
2005 433
2006 and thereafter $5,379
- -------------------------------------------------------------
5. INCOME TAXES
At December 31, 2000, tax-related regulatory assets and liabilities were $12.4
million and $16.0 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:
2000 1999 1998
- ------------------------------------------------------------------
(in thousands)
Total provision for income taxes
Federal --
Currently payable $11,102 $12,968 $ 6,763
Deferred 75 (3,329) 5,812
- ------------------------------------------------------------------
11,177 9,639 12,575
- ------------------------------------------------------------------
State --
Currently payable 1,744 2,193 1,327
Deferred 653 (24) 1,199
- ------------------------------------------------------------------
2,397 2,169 2,526
- -----------------------------------------------------------------
Total $13,574 $11,808 $15,101
==================================================================
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:
2000 1999
--------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $76,901 $76,282
Property basis differences 5,904 6,917
Other 17,807 12,031
- ----------------------------------------------------------------
Total 100,612 95,230
- ----------------------------------------------------------------
Deferred tax assets:
Pension and other benefits 9,744 6,965
Other 7,662 5,777
- ----------------------------------------------------------------
Total 17,406 12,742
- ----------------------------------------------------------------
Net deferred tax liabilities 83,206 82,488
Portions included in current assets, net (3,450) (2,170)
- ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $79,756 $80,318
================================================================
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 $ 0.7 million in 2000, 1999 and 1998. At December 31, 2000, 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:
2000 1999 1998
-----------------------------
Federal statutory tax rate 35% 35% 35%
State income tax, net of
federal income tax benefit 4 4 4
Other (2) (5) (2)
----------------------------------------------------------------
Effective income tax rate 37% 34% 37%
================================================================
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.
II-191
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
6. 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.
7. LONG-TERM DEBT AND LONG-TERM DEBT
DUE WITHIN ONE YEAR
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 $0.4 million in 2000,
$16.2 million in 1999 and $30.4 million in 1998. Included in the 1999 maturities
and retirements is the purchase by the Company of all $15 million outstanding of
its 7 7/8% Series First Mortgage Bonds due May 1, 2025.
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.
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:
2000 1999
---------------------
(in thousands)
Bond sinking fund requirement $ 642 $650
Less:
Portion to be satisfied by
certifying property additions 642 650
- -------------------------------------------------------------------
Cash sinking fund requirement - -
Other long-term debt maturities 30,698 704
- -------------------------------------------------------------------
Total $30,698 $704
===================================================================
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
certifying property additions in 2000 and by cash redemptions in 1999. It is
anticipated that the 2001 requirement will be satisfied by certifying property
additions. Sinking fund requirements and/or maturities through 2005 applicable
to long-term debt are as follows: $30.7 million in 2001; $0.6 million in 2002;
$20.5 million in 2003; $0.5 million in 2004; and $0.4 million in 2005.
8. COMMON STOCK DIVIDEND
RESTRICTIONS
The Company's Indenture contains certain limitations on the payment of cash
dividends on common stock. At December 31, 2000, approximately $68 million of
retained earnings was restricted against the payment of cash dividends on common
stock under the terms of the Indenture.
II-192
NOTES (continued)
Savannah Electric and Power Company 2000 Annual Report
9. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 2000 and 1999 are as follows (in
thousands):
Net Income After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ---------------------------------------------------------------------
March 2000 $52,390 $ 6,583 $ 1,643
June 2000 72,780 14,100 6,287
September 2000 98,849 24,060 12,351
December 2000 71,699 5,939 2,688
March 1999 $47,098 $ 5,315 $ 1,209
June 1999 61,692 12,173 5,268
September 1999 91,849 26,759 13,705
December 1999 50,955 4,355 2,901
- ---------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.
The quarterly operating income information above has been reclassified to
reflect the Company's current presentation of income tax expense.
11-193
SELECTED FINANCIAL AND OPERATING DATA 1996-2000
Savannah Electric and Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $295,718 $251,594 $254,455 $226,277 $234,074
Net Income after Dividends
on Preferred Stock (in thousands) $22,969 $23,083 $23,644 $23,847 $23,940
Cash Dividends
on Common Stock (in thousands) $24,300 $25,200 $23,500 $20,500 $19,600
Return on Average Common Equity (percent) 13.13 13.16 13.45 13.71 14.08
Total Assets (in thousands) $594,227 $570,218 $555,799 $547,352 $544,900
Gross Property Additions (in thousands) $27,290 $29,833 $18,071 $18,846 $28,950
- ----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $174,994 $174,847 $175,865 $175,631 $172,284
Preferred stock - - - 35,000 35,000
Company obligated mandatorily
redeemable preferred securities 40,000 40,000 40,000 - -
Long-term debt 116,902 147,147 163,443 142,846 164,406
- ----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $331,896 $361,994 $379,308 $353,477 $371,690
============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 52.7 48.3 46.4 49.7 46.4
Preferred stock - - - 9.9 9.4
Company obligated mandatorily
redeemable preferred securities 12.1 11.0 10.5 - -
Long-term debt 35.2 40.7 43.1 40.4 44.2
- ----------------------------------------------------------------------------------------------------------------------------
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+ AA- AA- AA- A+
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's BBB+ A- A A A
============================================================================================================================
Customers (year-end):
Residential 115,646 112,891 110,437 109,092 106,657
Commercial 15,727 15,433 15,328 14,233 13,877
Industrial 75 67 63 64 65
Other 444 417 377 1,129 1,097
- ----------------------------------------------------------------------------------------------------------------------------
Total 131,892 128,808 126,205 124,518 121,696
============================================================================================================================
Employees (year-end): 554 533 542 535 571
- ----------------------------------------------------------------------------------------------------------------------------
II-194
SELECTED FINANCIAL AND OPERATING DATA 1996-2000 (continued)
Savannah Electric and Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $129,520 $112,371 $109,393 $ 96,587 $101,607
Commercial 102,116 88,449 86,231 78,949 80,494
Industrial 40,839 32,233 37,865 35,301 37,077
Other 10,147 9,212 8,838 8,621 8,804
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 282,622 242,265 242,327 219,458 227,982
Sales for resale - non-affiliates 4,748 3,395 4,548 3,467 1,998
Sales for resale - affiliates 4,974 4,151 3,016 2,052 3,130
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 292,344 249,811 249,891 224,977 233,110
Other revenues 3,374 1,783 4,564 1,300 964
- ----------------------------------------------------------------------------------------------------------------------------------
Total $295,718 $251,594 $254,455 $226,277 $234,074
==================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,671,089 1,579,068 1,539,792 1,428,337 1,456,651
Commercial 1,369,448 1,287,832 1,236,337 1,156,078 1,141,218
Industrial 800,150 713,448 900,012 881,261 838,753
Other 135,824 132,555 131,142 124,490 126,215
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 3,976,511 3,712,903 3,807,283 3,590,166 3,562,837
Sales for resale - non-affiliates 77,481 51,548 53,294 94,280 91,610
Sales for resale - affiliates 88,646 76,988 58,415 54,509 41,808
- ----------------------------------------------------------------------------------------------------------------------------------
Total 4,142,638 3,841,439 3,918,992 3,738,955 3,696,255
==================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.75 7.12 7.10 6.76 6.98
Commercial 7.46 6.87 6.97 6.83 7.05
Industrial 5.10 4.52 4.21 4.01 4.42
Total retail 7.11 6.52 6.36 6.11 6.40
Sales for resale 5.85 5.87 6.77 3.71 3.84
Total sales 7.06 6.50 6.38 6.02 6.31
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,593 14,100 14,061 13,231 13,771
Residential Average Annual
Revenue Per Customer $1,131.08 $1,003.39 $998.94 $894.73 $960.58
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 788 788 788 788 788
Maximum Peak-Hour Demand (megawatts):
Winter 724 719 582 625 666
Summer 878 875 846 802 811
Annual Load Factor (percent) 53.4 51.2 54.9 54.3 53.1
Plant Availability Fossil-Steam (percent): 78.5 72.8 72.9 93.7 77.6
- ----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 51.6 44.6 41.6 34.4 27.7
Oil and gas 6.9 12.3 12.9 5.2 3.1
Purchased power -
From non-affiliates 7.7 5.3 3.4 1.4 2.1
From affiliates 33.8 37.8 42.1 59.0 67.1
- ----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==================================================================================================================================
II-195
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 2001
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 2001
Annual Meetings of Shareholders.
The ages of directors and executive officers in Item 10 set forth below are
as of December 31, 2000.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Identification of directors of SAVANNAH.
G. Edison Holland, Jr.
President and Chief Executive Officer
Age 48
Served as Director since 7-15-97
Gus H. Bell (1)
Age 63
Served as Director since 7-20-99
Archie H. Davis (1)
Age 59
Served as Director since 2-18-97
Walter D. Gnann (1)
Age 65
Served as Director since 5-17-83
Robert B. Miller, III (1)
Age 55
Served as Director since 5-17-83
Arnold M. Tenenbaum (1)
Age 64
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 17, 2000) for one
year until the next annual meeting or until a successor is elected and
qualified.
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 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.
G. Edison Holland, Jr.
President, Chief Executive Officer and Director
Age 48
Served as Executive Officer since 7-15-97
Anthony R. James
Vice President - Power Generation
Age 50
Served as Executive Officer since 7-27-00
W. Miles Greer
Vice President - Customer Operations and
External Affairs
Age 57
Served as Executive Officer since 11-20-85
Kirby R. Willis
Vice President, Treasurer, Chief Financial Officer
and Assistant Corporate Secretary
Age 49
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 27, 2000 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 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.
III-1
Family relationships.
None.
Business experience.
G. Edison Holland, Jr. - President and Chief Executive Officer since 1997. He
previously served as Vice President of Power
Generation/Transmission and Corporate Counsel of GULF from 1995 to 1997.
Served as a partner in the law firm of Beggs & Lane from 1979 to 1997.
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 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 - 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.
Anthony R. James - Vice President - Power Generation and Senior Production
Officer since 2000. He also serves as Central Cluster Manager at GEORGIA's Plant
Scherer. 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 effective 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 four most highly compensated
executive officers of SAVANNAH serving during 2000.
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.
President, 2000 295,812 243,263 24,438 25,667 - 15,453
Chief Executive 1999 254,914 42,626 21,588 8,375 166,052 13,392
Officer, Director 1998 233,330 26,019 17,309 7,951 128,608 8,246
Anthony R. James4 2000 175,048 161,442 - 12,752 - 7,582
Vice President, 1999 - - - - - -
1998 - - - - - -
W. Miles Greer 2000 177,013 100,923 601 13,416 - 16,982
Vice President 1999 168,713 21,322 1,874 6,130 79,476 15,150
1998 160,207 16,054 13 4,901 69,000 13,179
Kirby R. Willis
Vice President, 2000 162,279 97,394 4,908 8,785 - 12,159
Chief Financial 1999 156,068 19,546 259 5,028 79,476 11,767
Officer, Treasurer 1998 155,236 15,554 13 4,748 69,000 10,581
Lewis A. Jeffers5 2000 142,850 96,835 2,856 7,543 - 7,245
Vice President 1999 134,538 19,023 379 3,809 63,146 6,972
1998 - - - - - -
1 Tax reimbursement by SAVANNAH on certain personal benefits, including
membership fees of $11,669 for Mr. Holland, Jr. in 1998.
2 Payouts made in 1999
and 2000 for the four-year performance periods ending December 31, 1998 and
1999, respectively.
3 SAVANNAH contributions 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 Benefit Sharing
- ---- --- ---- ---------- -----------------------
G. Edison Holland, Jr. $6,853 $810 $7,790 $489
Anthony R. James 6,772 810 - -
W. Miles Greer 7,525 810 8,647 -
Kirby R. Willis 5,954 810 5,395 -
Lewis A. Jeffers 6,435 810 - -
4 Mr. James was named an executive officer effective July 27, 2000.
5 Mr. Jeffers was named an executive officer of SAVANNAH effective November 2,
1999 and transferred to ALABAMA effective June 24, 2000.
III-3
STOCK OPTION GRANTS IN 2000
Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of SAVANNAH during the year ending December 31,
2000.
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted6 Fiscal Year7 ($/Sh)6 Date6 Present Value($)8
-----------------------------------------------------------------------------------------------------------------
SAVANNAH
G. Edison Holland, Jr. 25,667 0.4 23.25 02/18/2010 147,842
Anthony R. James 12,752 0.2 23.25 02/18/2010 73,452
W. Miles Greer 13,416 0.2 23.25 02/18/2010 77,276
Kirby R. Willis 8,785 0.1 23.25 02/18/2010 50,602
Lewis A. Jeffers 7,543 0.1 23.25 02/18/2010 43,448
6 Performance Stock Plan grants were made on February 18, 2000, 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 fair market value of SOUTHERN's common
stock on the date granted. Options may be transferred to family members,
family trusts, and family limited partnerships.
7 A total of 6,977,038 stock options were granted in 2000.
8 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:
Volatility rate of return opportunity Term before after
vesting vesting
- -------------------------------------------------------------------------------------------------------------------
Black-Scholes Assumptions 22.14% 6.52% 50% 10 years 7.79% 12.40%
These assumptions reflect the effects of cash dividend equivalents paid to
participants under the Performance Dividend Plan assuming targets are met.
III-4
AGGREGATED STOCK OPTION EXERCISES IN 2000 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 2000 by the
named executive officers and the value of unexercised options held by them as of
December 31, 2000.
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options at Options at
Fiscal Fiscal
Year-End (#) Year-End($)9
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)10 Unexercisable Unexercisable
- -------------------------------------------------------------------------------------------------------------
SAVANNAH
G. Edison Holland, Jr. 18,323 220,862 32,261/33,900 325,274/310,486
Anthony R. James - - 8,456/17,259 77,991/157,055
W. Miles Greer 8,654 76,354 10,235/19,136 93,074/171,646
Kirby R. Willis 4,038 37,604 13,574/13,720 128,819/120,111
Lewis A. Jeffers - - 1,270/10,082 8,493/92,410
9 This column represents the excess of the fair market value of SOUTHERN's common
stock of $33.25 per share, as of December 31, 2000, 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, 2000.
10 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 Messrs. Holland,
James and Jeffers. Compensation for pension purposes is limited to the average
of the highest three of the final 10 years' compensation -- base salary plus the
excess of annual and long-term incentive compensation over 25 percent of base
salary (reported under column titled "Salary", "Bonus", and "Long-Term Incentive
Payouts" in the Summary Compensation Table on page III-3).
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 (although married employees are required to have
their pension benefits paid in one of various joint and survivor annuity forms,
unless the employee elects otherwise with the spouse's consent) or computation
of the Social Security offset which would apply in most cases. This offset
amounts to one-half of the estimated Social Security benefit (primary insurance
amount) in excess of $3,900 per year times the number of years of accredited
service, divided by the total possible years of accredited service to normal
retirement age.
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, 2000, the applicable compensation levels and years
of accredited service for SAVANNAH's named executives are presented in the
following table:
Compensation Accredited
Name Level Years of Service
G. Edison Holland, Jr.9 $431,348 17
Anthony R. James 246,604 21
W. Miles Greer10 237,392 16
Kirby R. Willis 225,952 26
Lewis A. Jeffers 197,400 21
9 The number of accredited years of service includes 9 years and 3 months
credited to Mr. Holland pursuant to a supplemental pension agreement.
10 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 2000 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 2000 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 per quarter
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 the respective companies' 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, 2000 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 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.
If a change in control affects only a subsidiary of SOUTHERN, these
payments would only be made to executives of the affected subsidiary who are
involuntarily terminated as a result of that change in control.
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, 2000. 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, 2000.
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
- ------------------ -------------- --------------------------
Gus H. Bell, III SOUTHERN Common 246
Archie H. Davis SOUTHERN Common 495
Walter D. Gnann SOUTHERN Common 2,689
G. Edison Holland, Jr. SOUTHERN Common 43,848
Robert B. Miller, III SOUTHERN Common 1,770
Arnold M. Tenenbaum SOUTHERN Common 1,124
Anthony R. James SOUTHERN Common 25,065
W. Miles Greer SOUTHERN Common 18,605
Kirby R. Willis SOUTHERN Common 23,240
The directors, nominees
and executive officers
as a group SOUTHERN Common 117,083
(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,
14,707 shares; Mr. Holland, 40,817 shares; Mr. James 12,707
shares, and Mr. Willis, 16,503 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 President of The Savannah Bank, N.A., Savannah,
Georgia. During 2000, 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 2000 were as follows:
SOUTHERN filed Current Reports on Form 8-K:
Date of event: November 27, 2000
Items reported: Items 5 and 7
Date of event: December 6, 2000
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, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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
President and
Chief Executive Officer
(Principal Executive Officer)
Gale E. Klappa
Financial Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
W. Dean Hudson
Vice President, 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
H. Allen Franklin Gerald J. St. Pe'
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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: Elmer B. Harris, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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.
Elmer B. Harris
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 John T. Porter
H. Allen Franklin Robert D. Powers
R. Kent Henslee Andreas Renschler
Carl E. Jones, Jr. C. Dowd Ritter
James K. Lowder James H. Sanford
Wallace D. Malone, Jr. John Cox Webb, IV
Thomas C. Meredith James W. Wright
William V. Muse
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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 28, 2001
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:
Daniel P. Amos James R. Lientz, Jr.
Juanita P. Baranco G. Joseph Prendergast
William A. Fickling, Jr. William Jerry Vereen
H. Allen Franklin Carl Ware
L. G. Hardman III E. Jenner Wood, III
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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
Comptroller and Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Fred C. Donovan, Sr. W. Deck Hull, Jr.
H. Allen Franklin Barbara H. Thames
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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: Dwight H. Evans, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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.
Dwight H. Evans
President, Chief Executive Officer and Director
(Principal Executive Officer)
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Robert S. Gaddis George A. Schloegel
Linda T. Howard Philip J. Terrell
Aubrey K. Lucas Gene Warr
Malcolm Portera
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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: G. Edison Holland, Jr., President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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.
G. Edison Holland, Jr.
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
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 28, 2001
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 L.P. Holdings Corp. Georgia
Georgia Power Capital, L.P. 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
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
- ----------------------------------------------------- -- ---------------------
*This information is as of December 31, 2000. In addition, the list omits
certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K Item
601.
IV-5
ARTHUR ANDERSEN LLP
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 28, 2001 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, 33-30171, 33-54415,
33-57951, 33-58371, 33-60427, 333-09077, 333-44127, 333-44261, 333-64871 and
333-31808.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 2001
IV-6
ARTHUR ANDERSEN LLP
Exhibit 23(b)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 28, 2001 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. 333-67453.
/s/ Arthur Andersen LLP
Birmingham, Alabama
March 22, 2001
IV-7
Exhibit 23(c)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 28, 2001 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 No. 333-75193.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 2001
IV-8
Exhibit 23(d)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 28, 2001 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
Nos. 33-50165 and 333-42033.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 2001
IV-9
ARTHUR ANDERSEN LLP
Exhibit 23(e)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 28, 2001 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 22, 2001
IV-10
ARTHUR ANDERSEN LLP
Exhibit 23(f)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 28, 2001 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. 333-46171.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 2001
IV-11
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-12
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-13
ARTHUR ANDERSEN LLP
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 28, 2001.
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 28, 2001
IV-14
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-15
ARTHUR ANDERSEN LLP
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
28, 2001. 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 28, 2001
IV-16
ARTHUR ANDERSEN LLP
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 28, 2001. 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 28, 2001
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves
2000, 1999 and 1998
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, 2000, 1999 AND 1998
(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
2000................... $21,834 $31,329 $39 $31,403 (Note) $21,799
1999................... 11,268 35,476 - 24,910 (Note) 21,834
1998................... 9,613 31,707 - 30,052 (Note) 11,268
- -------------------
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, 2000, 1999 AND 1998
(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
2000........................ $4,117 $9,093 $- $ 6,973 (Note) $6,237
1999........................ 1,855 13,995 - 11,733 (Note) 4,117
1998........................ 2,272 7,702 - 8,119 (Note) 1,855
- -------------------
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, 2000, 1999 AND 1998
(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
2000.......................... $7,000 $10,794 $- $12,694 (Note) $5,100
1999.......................... 5,500 14,406 - 12,906 (Note) 7,000
1998.......................... 3,000 17,856 - 15,356 (Note) 5,500
8,888 ($3
- -------------------
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, 2000, 1999 AND 1998
(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
2000.......................... $1,026 $2,702 $- $2,426 (Note) $1,302
1999.......................... 996 2,230 - 2,200(Note) 1,026
1998.......................... 796 2,288 - 2,088 (Note) 996
- -------------------
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, 2000, 1999 AND 1998
(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
2000.......................... $697 $1,156 $14 $1,296 (Note) $571
1999.......................... 621 1,964 - 1,888 (Note) 697
1998.......................... 698 1,510 31 1,618 (Note) 621
- -------------------
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, 2000, 1999 AND 1998
(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
2000.......................... $237 $999 $- $829 (Note) $407
1999.......................... 284 594 - 641 (Note) 237
1998.......................... 354 417 - 487 (Note) 284
- -------------------
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, respectively, 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.
(1) Underwriting Agreements
GEORGIA
(c) - Distribution Agreement dated November 29, 1995 between GEORGIA and Lehman Brothers Inc.; Donaldson, Lufkin &
Jenrette Securities Corporation; J. P. Morgan Securities Inc.; Salomon Brothers Inc and Smith Barney Inc.
relating to $300,000,000 First Mortgage Bonds Secured Medium-Term Notes. (Designated in GEORGIA's Form 10-K
for the year ended December 31, 1995, as Exhibit 1(c).)
(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 August 10, 1998.(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 and Form 8-K
dated August 10, 1998, File No. 1-3164, as Exhibit 4.4.)
* (b) 2 - Amendment to Charter of ALABAMA dated January 10, 2001.
E-1
(b) 3 - By-laws of ALABAMA as amended effective July 23, 1993, and as presently in effect.(Designated in Form U-1,
File No. 70-8191, as Exhibit A-2.)
GEORGIA
(c) 1 - Charter of GEORGIA and amendments thereto through January 26, 1998.(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), 33-14367 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) and in GEORGIA's Form 10-K for the year ended December 31, 1997, File No.
1-6468, as Exhibit 3(c)2.)
* (c) 2 - Amendment to Charter of GEORGIA dated February 16, 2001.
* (c) 3 - By-laws of GEORGIA as amended effective November 15, 2000, and as presently in effect.
GULF
(d) 1 - Restated Articles of Incorporation of GULF and amendments thereto through January 28, 1998. (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 and in
GULF's Form 10-K for the year ended December 31, 1997, File No. 0-2429, as Exhibit 3(d)2.)
* (d) 2 - Amendment to Articles of Incorporation of GULF dated February 9, 2001.
* (d) 3 - By-laws of GULF as amended effective July 28, 2000, 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 December 31, 1997. (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 and in
MISSISSIPPI's Form 10-K for the year ended December 31, 1997, File No. 0-6849, as Exhibit 3(e)2.)
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* (e) 2 - Amendment to Articles of Incorporation of MISSISSIPPI dated March 8, 2001.
(e) 3 - By-laws of MISSISSIPPI as amended effective April 2, 1996, and as presently in effect. (Designated in Form
U5S for 1995, File No. 30-222-2, as Exhibit B-10.)
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.
(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 that dated as of 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 - 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) 4 - 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) 5 - 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) 6 - 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.)
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(a) 7 - 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) 8 - 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) 9 - 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) 10 - 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) 11 - 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) 12 - 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 The Chase Manhattan Bank (formerly Chemical Bank),
as Trustee, and indentures supplemental thereto through that dated as of 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.)
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(b) 2 - Subordinated Note Indenture dated as of January 1, 1996, between ALABAMA and The Chase Manhattan Bank
(formerly Chemical 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 The Chase Manhattan Bank, as
Trustee, and indentures supplemental thereto through that dated as of 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 The Chase Manhattan Bank, as Trustee,
and indentures supplemental thereto through that dated May 18, 2000. (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 and in Form 8-K dated May 11, 2000, File No. 1-3164, as
Exhibit 4.2.)
(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.)
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GEORGIA
(c) 1 - Indenture dated as of March 1, 1941, between GEORGIA and The Chase Manhattan Bank (formerly Chemical 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 - Subordinated Note Indenture dated as of August 1, 1996, between GEORGIA and 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.)
(c) 3 - Subordinated Note Indenture dated as of June 1, 1997, between GEORGIA and The Chase Manhattan Bank, as
Trustee, and indentures supplemental thereto through that dated as of 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.)
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(c) 4 - Senior Note Indenture dated as of January 1, 1998, between GEORGIA and The Chase Manhattan Bank, as Trustee,
and indentures supplemental thereto through that dated as of February 23, 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) and in Form 8-K dated February 16, 2001, File No. 1-6469 as Exhibit 4.2.)
(c) 5 - 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) 6 - 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) 7 - 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) 8 - 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) 9 - 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) 10 - 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) 11 - 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) 12 - 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.)
GULF
(d) 1 - Indenture dated as of September 1, 1941, between GULF and The Chase Manhattan Bank (formerly The Chase
Manhattan Bank (National Association)), 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,
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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 The Chase Manhattan Bank, as
Trustee, and indentures supplemental thereto through that dated as of January 1, 1998. (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 and in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.2.)
(d) 3 - Senior Note Indenture dated as of January 1, 1998, between GULF and The Chase Manhattan Bank, as Trustee, and
indenture supplemental thereto dated as of August 24, 1999. (Designated in Form 8-K dated June 17, 1998,
File No. 0-2429, as Exhibits 4.1 and 4.2 and in Form 8-K dated August 17, 1999, 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 - 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.)
(d) 7 - 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.)
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.)
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(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, 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 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
indenture supplemental thereto dated as of March 1, 1998. (Designated in Form 8-K dated March 9, 1998, File
No. 1-5072, as Exhibits 4.1 and 4.2.)
(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.)
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(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 July 17, 1981, between SCS and Mirant. (Designated in SOUTHERN's Form 10-K for
the year ended December 31, 1985, File No. 1-3526, as Exhibit 10(a)(2).)
(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.)
* (a) 6 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and
SCS.
(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).)
E-10
(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).)
(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.)
E-11
(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.)
(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.)
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(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).)
(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.)
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(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).)
(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.)
E-14
(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 Executive Productivity Improvement Plan, Amended and Restated effective January 1, 2001.
(a) 53 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Five. (Designated in SOUTHERN's Form 10-K for the year ended December 31,
1998, File No. 1-3526 as Exhibit 10(a)61 and in SOUTHERN's Form 10-K for the year ended December 31, 1999,
File No. 1-3526, as Exhibit 10(a)61.)
* (a) 54 - Amendment Number Six to The Southern Company Employee Savings Plan.
(a) 55 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Three. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1998, File No. 1-3526 as Exhibit 10(a)62 and in SOUTHERN's Form 10-K for the year ended December
31, 1999, File No. 1-3526, as Exhibit 10(a)63.)
* (a) 56 - Amendment Number Four to The Southern Company Employee Stock Ownership Plan.
* (a) 57 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 2000.
* (a) 58 - Southern Company Performance Pay Plan (Shareholder Approved) effective January 1, 2000.
# * (a) 59 - The Deferred Compensation Plan for the Directors of The Southern Company, Amended and Restated effective
February 19, 2001.
# (a) 60 - 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) 61 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001.
# (a) 62 - 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) 63 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January
1, 2000.
# * (a) 64 - The Southern Company Performance Dividend Plan, Amended and Restated effective December 11, 2000.
(a) 65 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Four. (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 and in SOUTHERN's Form 10-K for the year ended December 31, 1999, File No. 1-3526, as Exhibit
10(a)72.)
* (a) 66 - Amendment Number Five and Amendment Number Six to The Southern Company Pension Plan.
# * (a) 67 - The Southern Company Performance Stock Plan, Amended and Restated effective January 1, 2000.
# * (a) 68 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective July 10, 2000.
# (a) 69 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Seven. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No.
1-3526, as Exhibit 10(a)82, in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as
Exhibit 10(a)76 and in SOUTHERN's Form 10-K for the year ended December 31, 1999, File No. 1-3526, as Exhibit
10(a)76.)
# * (a) 70 - Amendment Number Eight to The Southern Company Performance Sharing Plan.
# * (a) 71 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective July 10, 2000.
* (a) 72 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000.
# * (a) 73 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000.
# (a) 74 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Henry Allen Franklin and First Amendment and
Assignment to SCS. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526
as Exhibit 10(a)80 and in SOUTHERN's Form 10-K for the year ended December 31, 1999, File No. 1-3526, as
Exhibit 10(a)84.)
# (a) 75 - 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.)
E-16
# (a) 76 - 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) 77 - Deferred Compensation Agreement between SOUTHERN, Southern Energy Resources, Inc. and Gale E. Klappa and
First Amendment and Assignment to SCS. (Designated in SOUTHERN's Form 10-K for the year ended December 31,
1999, File No. 1-3526, as Exhibit 10(a)87.)
# (a) 78 - Deferred Compensation Agreement between SOUTHERN, Southern Energy Resources, Inc. and S. Marce Fuller.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1999, File No. 1-3526, as Exhibit
10(a)88.)
# * (a) 79 - Amended and Restated Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden.
# * (a) 80 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and A. W. Dahlberg.
# * (a) 81 - Amended and Restated Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans.
# (a) 82 - Change in Control Agreement between SOUTHERN, ALABAMA and Banks Harry Farris. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)88.)
# * (a) 83 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Henry Allen Franklin.
# * (a) 84 - Amended and Restated Change in Control Agreement between SOUTHERN, Southern Nuclear and William G. Hairston,
III.
# * (a) 85 - Amended and Restated Change in Control Agreement between SOUTHERN, ALABAMA and Elmer B. Harris.
# * (a) 86 - Amended and Restated Change in Control Agreement between SOUTHERN, SAVANNAH and G. Edison Holland, Jr.
# * (a) 87 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and C. Alan Martin.
# * (a) 88 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Charles Douglas McCrary.
# * (a) 89 - Amended and Restated Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe.
# * (a) 90 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Stephen A. Wakefield.
E-17
# * (a) 91 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and W. Lawrence Westbrook.
# * (a) 92 - Amended and Restated Change in Control Agreement between SOUTHERN, SCS and Gale E. Klappa.
# (a) 93 - Change in Control Agreement between SOUTHERN, Southern Energy Resources, Inc. and S. Marce Fuller and First
Amendment thereto. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1999, File No.
1-3526, as Exhibit 10(a)103.)
# * (a) 94 - Deferred Compensation Agreement between SOUTHERN and William L. Westbrook.
# * (a) 95 - Deferred Compensation Agreement between SOUTHERN and Alfred W. Dahlberg, III.
# * (a) 96 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000.
# * (a) 97 - Change in Control Agreement between SOUTHERN, SCS and Robert H. Haubein, Jr..
# * (a) 98 - Deferred Compensation Agreement between SOUTHERN, SCS and Stephen A. Wakefield.
# * (a) 99 - Deferred Compensation Agreement between SOUTHERN and Wayne T. Dalke.
# * (a) 100 - Master Separation and Distribution Agreement dated as of September 1, 2000 between SOUTHERN and Mirant.
# * (a) 101 - Indemnification and Insurance Matters Agreement dated as of September 1, 2000 between SOUTHERN and Mirant.
# * (a) 102 - Tax Indemnification Agreement dated as of September 1, 2000 among SOUTHERN and its affiliated companies and
Mirant and its affiliated companies.
# * (a) 103 - 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.
# * (a) 104 - 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.
# * (a) 105 - Deferred Cash Compensation Trust Agreement
for Directors of SOUTHERN and its subsidiaries, dated
as of January 1, 2000, between Wachovia Bank, N.A,
SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI, and
SAVANNAH.
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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.
* (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 Executive Productivity Improvement Plan, Amended and Restated effective January 1,
2001. See Exhibit 10(a)52 herein.
(b) 14 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Five. See Exhibit 10(a)53 herein.
E-19
* (b) 15 - Amendment Number Six to The Southern Company Employee Savings Plan. See Exhibit 10(a)54 herein.
(b) 16 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Three. See Exhibit 10(a)55 herein.
* (b) 17 - Amendment Number Four to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)56 herein.
* (b) 18 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)57 herein.
* (b) 19 - Southern Company Performance Pay Plan (Shareholder Approved) effective January 1, 2000. See Exhibit 10(a)58
herein.
# * (b) 20 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See
Exhibit 10(a)61 herein.
# (b) 21 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)60 herein.
# * (b) 22 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January
1, 2000. See Exhibit 10(a)63 herein.
(b) 23 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Four. See Exhibit 10(a)65 herein.
* (b) 24 - Amendment Number Five and Amendment Number Six to The Southern Company Pension Plan. See Exhibit 10(a)66
herein.
# * (b) 25 - The Southern Company Performance Stock Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)67 herein.
# * (b) 26 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)68 herein.
# * (b) 27 - The Southern Company Performance Dividend Plan, Amended and Restated effective December 11, 2000. See
Exhibit 10(a)64 herein.
# (b) 28 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Seven. See Exhibit 10(a)69 herein.
# * (b) 29 - Amendment Number Eight to The Southern Company Performance Sharing Plan. See Exhibit 10(a)70 herein.
# * (b) 30 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)71 herein.
E-20
* (b) 31 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)72 herein.
# (b) 32 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)73 herein.
# (b) 33 - Change in Control Agreement between SOUTHERN, ALABAMA and Banks Harry Farris. See Exhibit 10(a)82 herein.
# * (b) 34 - Amended and Restated Change in Control Agreement between SOUTHERN, ALABAMA and Elmer B. Harris. See Exhibit
10(a)85 herein.
# (b) 35 - 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) 36 - Deferred Compensation Plan for Directors of Alabama Power Company, Amended and Restated as of
January 1, 2000.
# * (b) 37 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit
10(a)96 herein.
# * (b) 38 - 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)103 herein.
# * (b) 39 - 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) 104 herein.
# * (b) 40 - Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of
January 1, 2000, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI, and SAVANNAH.
See Exhibit 10(a)105 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.
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(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.
(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.
E-22
(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.
(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.
E-23
(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.
(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 - Certificate of Limited Partnership of Georgia Power Capital. (Designated in Certificate of Notification,
File No. 70-8461, as Exhibit B.)
(c) 44 - Amended and Restated Agreement of Limited Partnership of Georgia Power Capital, dated as of December 1,
1994. (Designated in Certificate of Notification, File No. 70-8461, as Exhibit C.)
(c) 45 - Action of General Partner of Georgia Power Capital creating the Series A Preferred Securities. (Designated
in Certificate of Notification, File No. 70-8461, as Exhibit D.)
(c) 46 - Guarantee Agreement of GEORGIA dated as of December 1, 1994, for the benefit of the holders from time to time
of the Series A Preferred Securities. (Designated in Certificate of Notification, File No. 70-8461, as
Exhibit G.)
E-24
# * (c) 47 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
2001. See Exhibit 10(a)52 herein.
(c) 48 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Five. See Exhibit 10(a)53 herein.
* (c) 49 - Amendment Number Six to The Southern Company Employee Savings Plan. See Exhibit 10(a)54 herein.
(c) 50 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Three. See Exhibit 10(a)55 herein.
* (c) 51 - Amendment Number Four to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)56 herein.
* (c) 52 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)57 herein.
* (c) 53 - Southern Company Performance Pay Plan (Shareholder Approved) effective January 1, 2000. See Exhibit 10(a)58
herein.
# * (c) 54 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See
Exhibit 10(a)61 herein.
# (c) 55 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)60 herein.
# * (c) 56 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January
1, 2000. See Exhibit 10(a)63 herein.
(c) 57 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Four. See Exhibit 10(a)65 herein.
* (c) 58 - Amendment Number Five and Amendment Number Six to The Southern Company Pension Plan. See Exhibit 10(a)66
herein.
# * (c) 59 - The Southern Company Performance Stock Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)67 herein.
# * (c) 60 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)68 herein.
# * (c) 61 - The Southern Company Performance Dividend Plan, Amended and Restated effective December 11, 2000. See
Exhibit 10(a)64 herein.
# (c) 62 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Seven. See Exhibit 10(a)69 herein.
E-25
# * (c) 63 - Amendment Number Eight to The Southern Company Performance Sharing Plan. See Exhibit 10(a)70 herein.
# * (c) 64 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)71 herein.
* (c) 65 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)72 herein.
# * (c) 66 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)73 herein.
# (c) 67 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Henry Allen Franklin and First Amendment and
Assignment to SCS. See Exhibit 10(a)74 herein.
# (c) 68 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Warren Y. Jobe. See Exhibit 10(a)76 herein.
# * (c) 69 - Amended and Restated Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe. See
Exhibit 10(a)89 herein.
# (c) 70 - 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) 71 - Deferred Compensation Plan For Directors of Georgia Power Company, Amended and Restated Effective February
21, 2001.
# * (c) 72 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit
10(a)96 herein.
# * (c) 73 - 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)103 herein.
# * (c) 74 - 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)104 herein.
# * (c) 75 - Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of
January 1, 2000, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI, and SAVANNAH.
See Exhibit 10 (a)105 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.
E-26
* (d) 2 - Interchange contract dated February 17, 2000, between ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and
SCS. See Exhibit 10(a)6 herein.
(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 Executive Productivity Improvement Plan, Amended and Restated effective January 1,
2000. See Exhibit 10(a)52 herein.
(d) 11 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Five. See Exhibit 10(a)53 herein.
* (d) 12 - Amendment Number Six to The Southern Company Employee Savings Plan. See Exhibit 10(a)54 herein.
(d) 13 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Three. See Exhibit 10(a)55 herein.
* (d) 14 - Amendment Number Four to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)56 herein.
* (d) 15 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)57 herein.
E-27
* (d) 16 - Southern Company Performance Pay Plan (Shareholder Approved) effective January 1, 2000. See Exhibit 10(a)58
herein.
# * (d) 17 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See
Exhibit 10(a)61 herein.
# (d) 18 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)60 herein.
# * (d) 19 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January
1, 2000. See Exhibit 10(a)63 herein.
(d) 20 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Four. See Exhibit 10(a)65 herein.
* (d) 21 - Amendment Number Five and Amendment Number Six to The Southern Company Pension Plan. See Exhibit 10(a)66
herein.
# * (d) 22 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)71 herein.
* (d) 23 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)72 herein.
# * (d) 24 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)73 herein.
# * (d) 25 - Amended and Restated Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden. See Exhibit
10(a)79 herein.
# * (d) 26 - The Southern Company Performance Stock Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)67 herein.
# * (d) 27 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)68 herein.
# * (d) 28 - The Southern Company Performance Dividend Plan, Amended and Restated effective December 11, 2000. See
Exhibit 10(a)64 herein.
# (d) 29 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Seven. See Exhibit 10(a)69 herein.
# * (d) 30 - Amendment Number Eight to The Southern Company Performance Sharing Plan. See Exhibit 10(a)70 herein.
# (d) 31 - 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.)
E-28
# (d) 32 - Supplemental Pension Agreement between ALABAMA, GULF and Travis J. Bowden. See Exhibit 10(b)35 herein.
# * (d) 33 - Deferred Compensation Plan For Directors of Gulf Power Company, Amended and Restated Effective January 1,
2000 and First Amendment thereto.
# * (d) 34 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit
10(a)96 herein.
# * (d) 35 - 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)103 herein.
# * (d) 36 - 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)104 herein.
# * (d) 37 - Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of
January 1, 2000, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI, and SAVANNAH.
See Exhibit 10(a)105 herein.
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-29
# * (e) 8 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
2001. See Exhibit 10(a)52 herein.
(e) 9 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Five. See Exhibit 10(a)53 herein.
* (e) 10 - Amendment Number Six to The Southern Company Employee Savings Plan. See Exhibit 10(a)54 herein.
(e) 11 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Three. See Exhibit 10(a)55 herein.
* (e) 12 - Amendment Number Four to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)56 herein.
(e) 13 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)57 herein.
* (e) 14 - Southern Company Performance Pay Plan (Shareholder Approved) effective January 1, 2000. See Exhibit 10(a)58
herein.
# * (e) 15 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See
Exhibit 10(a)61 herein.
# (e) 16 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)60 herein.
# * (e) 17 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January
1, 2000. See Exhibit 10(a)63 herein.
(e) 18 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Four. See Exhibit 10(a)65 herein.
* (e) 19 - Amendment Number Five and Amendment Number Six to The Southern Company Pension Plan. See Exhibit 10(a)66
herein.
# * (e) 20 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)71 herein.
* (e) 21 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)72 herein.
# * (e) 22 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)73 herein.
# * (e) 23 - Amended and Restated Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans. See
Exhibit 10(a)81 herein.
E-30
# * (e) 24 - The Southern Company Performance Stock Plan, Amended and Restated effective January 1,2000. See Exhibit
10(a)67 herein.
# * (e) 25 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)68 herein.
# * (e) 26 - The Southern Company Performance Dividend Plan, Amended and Restated effective December 11, 2000. See
Exhibit 10(a)64 herein.
# (e) 27 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Seven. See Exhibit 10(a)69 herein.
# * (e) 28 - Amendment Number Eight to The Southern Company Performance Sharing Plan. See Exhibit 10(a)70 herein.
# (e) 29 - Deferred Compensation Plan for Directors of Mississippi Power Company, Amended and Restated Effective January
1, 2000. (Designated in MISSISSIPPI's Form 10-K for the year ended December 31, 1999, File No. 0-6849, as
Exhibit 10(e)37.)
# * (e) 30 - Amendment Number One to the Deferred Compensation Plan for Directors of Mississippi Power Company.
# * (e) 31 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit
10(a)96 herein.
# * (e) 32 - 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)103 herein.
# * (e) 33 - 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)104 herein.
# * (e) 34 - Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of
January 1, 2000, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI, and SAVANNAH.
See Exhibit 10(a)105 herein.
SAVANNAH
(f) 1 - Service contract dated as of March 3, 1988, between SCS and SAVANNAH. See Exhibit 10(a)3 herein.
* (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.
E-31
(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 Executive Productivity Improvement Plan, Amended and Restated effective January 1,
2000. See Exhibit 10(a)52 herein.
(f) 9 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Five. See Exhibit 10(a)53 herein.
* (f) 10 - Amendment Number Six to The Southern Company Employee Savings Plan. See Exhibit 10(a)54 herein.
(f) 11 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Three. See Exhibit 10(a)55 herein.
* (f) 12 - Amendment Number Four to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)56 herein.
# * (f) 13 - Supplemental Executive Retirement Plan of SAVANNAH, Amended and Restated effective October 26, 2000.
# * (f) 14 - Deferred Compensation Plan for Key Employees of SAVANNAH, Amended and Restated effective October 26, 2000.
(f) 15 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)57 herein.
* (f) 16 - Southern Company Performance Pay Plan (Shareholder Approved) effective January 1, 2000. See Exhibit 10(a)58
herein.
# (f) 17 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)60 herein.
# * (f) 18 - Deferred Compensation Plan for Directors of SAVANNAH, Amended and Restated effective October 26, 2000.
# * (f) 19 - Outside Directors Stock Plan for Subsidiaries of The Southern Company, Amended and Restated effective January
1, 2000. See Exhibit 10(a)63 herein.
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(f) 20 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Four. See Exhibit 10(a)65 herein.
* (f) 21 - Amendment Number Five and Amendment Number Six to The Southern Company Pension Plan. See Exhibit 10(a)66
herein.
# * (f) 22 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)76 herein.
* (f) 23 - Southern Company Change in Control Severance Plan, Amended and Restated effective July 10, 2000. See Exhibit
10(a)72 herein.
# * (f) 24 - Southern Company Executive Change in Control Severance Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)73 herein.
# * (f) 25 - Amended and Restated Change in Control Agreement between SOUTHERN, SAVANNAH and G. Edison Holland, Jr. See
Exhibit 10(a)86 herein.
# * (f) 26 - The Southern Company Deferred Compensation Plan, Amended and Restated effective February 23, 2001. See
Exhibit 10(a)61 herein.
# * (f) 27 - The Southern Company Performance Stock Plan, Amended and Restated effective January 1, 2000. See Exhibit
10(a)67 herein.
# * (f) 28 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective July 10, 2000.
See Exhibit 10(a)68 herein.
# * (f) 29 - The Southern Company Performance Dividend Plan, Amended and Restated effective December 11, 2000. See
Exhibit 10(a)64 herein.
# (f) 30 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Seven. See Exhibit 10(a)69 herein.
# * (f) 31 - Amendment Number Eight to The Southern Company Performance Sharing Plan. See Exhibit 10(a)70 herein.
# (f) 32 - Supplemental Pension Agreement between SAVANNAH, GULF and G. Edison Holland, Jr. See Exhibit 10(d)31 herein.
# * (f) 33 - Southern Company Change in Control Benefit Plan Determination Policy, effective July 10, 2000. See Exhibit
10(a)96 herein.
# * (f) 34 - Agreement for supplemental pension benefits between SAVANNAH and William Miles Greer.
# * (f) 35 - Agreement crediting additional service between SAVANNAH and William Miles Greer.
# * (f) 36 - 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)103 herein.
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# * (f) 37 - 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)104 herein.
# * (f) 38 - Deferred Cash Compensation Trust Agreement for Directors of SOUTHERN and its subsidiaries, dated as of
January 1, 2000, between Wachovia Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI, and SAVANNAH.
See Exhibit 10(a)105 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.
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GULF
* (d) - The consent of Arthur Andersen LLP is contained herein at page IV-9.
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.
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