<PAGE>

===============================================================================
                                    UNITED STATES
                         SECURITIES AND EXCHANGE COMMISSION
                               Washington, D.C. 20549

                                      FORM 10-K

                  (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                       OF THE SECURITIES EXCHANGE ACT OF 1934
                     For the Fiscal Year Ended December 31, 2001
                                         OR
                ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                       OF THE SECURITIES EXCHANGE ACT OF 1934
                       For the Transition Period from      to

Commission         Registrant, State of Incorporation,        I.R.S. Employer
File Number         Address and Telephone Number            Identification No.

    1-3526          The Southern Company                        58-0690070
                    (A Delaware Corporation)
                    270 Peachtree Street, N.W.
                    Atlanta, Georgia 30303
                    (404) 506-5000

    1-3164          Alabama Power Company                       63-0004250
                    (An Alabama Corporation)
                    600 North 18th Street
                    Birmingham, Alabama 35291
                    (205) 257-1000

    1-6468          Georgia Power Company                       58-0257110
                    (A Georgia Corporation)
                    241 Ralph McGill Boulevard, N.E.
                    Atlanta, Georgia 30308
                    (404) 506-6526

    0-2429          Gulf Power Company                          59-0276810
                    (A Maine Corporation)
                    One Energy Place
                    Pensacola, Florida 32520
                    (850) 444-6111

    0-6849          Mississippi Power Company                   64-0205820
                    (A Mississippi Corporation)
                    2992 West Beach
                    Gulfport, Mississippi 39501
                    (228) 864-1211

    1-5072          Savannah Electric and Power Company         58-0418070
                    (A Georgia Corporation)
                    600 East Bay Street
                    Savannah, Georgia 31401
                    (912) 644-7171

===============================================================================
<PAGE>


Securities registered pursuant to Section 12(b) of the Act:1

Each of the following classes or series of securities registered pursuant to
Section 12(b) of the Act is registered on the New York Stock Exchange.

Title of each class                                        Registrant
-------------------                                        -----------

Common Stock, $5 par value                               The Southern Company

Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.75% Cumulative Quarterly Income Preferred Securities 2
7 1/8% Trust Originated Preferred Securities3
6.875% Cumulative Quarterly Income Preferred Securities4

                    ---------------------------------------------------

Class A preferred, cumulative, $25 stated capital        Alabama Power Company
5.20% Series                        5.83% Series

Senior Notes
7 1/8% Series A         7% Series C
7% Series B           6.75% Series J

Company obligated mandatorily redeemable
preferred securities, $25 liquidation
amount
7.375% Trust Preferred Securities5
7.60% Trust Originated Preferred Securities6

                     ---------------------------------------------------

Senior Notes                                             Georgia Power Company
6 7/8% Series A              6 5/8% Series D
6.60% Series B

Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.75% Trust Preferred Securities7            7.60% Trust Preferred Securities8
7.75% Cumulative Quarterly Income Preferred Securities9
6.85% Trust Preferred Securities10


                  ------------------------------------------------------

===============================================================================

----------------------------
1 As of December 31, 2001.
2 Issued by Southern Company Capital Trust III and guaranteed by The Southern
Company.
3 Issued by Southern Company Capital Trust IV and guaranteed by The Southern
Company.
4 Issued by Southern Company Capital Trust V and guaranteed by The Southern
Company.
5 Issued by Alabama Power Capital Trust I and guaranteed by Alabama Power
Company.
6 Issued by Alabama Power Capital Trust II and guaranteed by Alabama Power
Company.
7 Issued by Georgia Power Capital Trust I and guaranteed by Georgia Power
Company.
8 Issued by Georgia Power Capital Trust II and guaranteed by Georgia Power
Company.
9 Issued by Georgia Power Capital Trust III and guaranteed by Georgia Power
Company.
10 Issued by Georgia Power Capital Trust IV and guaranteed by Georgia Power
Company.

<PAGE>


Company obligated mandatorily redeemable          Gulf Power Company
preferred securities, $25 liquidation amount
7.625% Cumulative Quarterly Income Preferred Securities11
7.00% Cumulative Quarterly Income Preferred Securities12
7.375% Trust Preferred Securities13

             ------------------------------------------------------

Depositary preferred shares,                      Mississippi Power Company
each representing
one-fourth of a share of preferred stock,
cumulative, $100 par value
6.32%Series               6.65% Series

Company obligated mandatorily redeemable
preferred securities, $25 liquidation
amount
7.75% Trust Originated Preferred Securities14

               ---------------------------------------------------

Company obligated mandatorily               Savannah Electric and Power Company
redeemable preferred securities,
$25 liquidation amount
6.85% Trust Preferred Securities15

Securities registered pursuant to Section 12(g) of the Act:16

Title of each class                                     Registrant
-------------------                                     ----------

Preferred stock, cumulative, $100 par value       Alabama Power Company
4.20% Series    4.60% Series    4.72% Series
4.52% Series    4.64% Series    4.92% Series

Class A preferred, cumulative, $100,000 stated capital
Auction (1993 Series)

Class A preferred, cumulative, $100 stated capital
Auction (1988 Series)

           ----------------------------------------------------------

Preferred stock, cumulative,                      Georgia Power Company
$100 stated value
$4.60 Series (1954)

           ----------------------------------------------------------



==============================================================================


---------------------
11 Issued by Gulf Power Capital Trust I and guaranteed by Gulf Power Company.
12 Issued by Gulf Power Capital Trust II and guaranteed by Gulf Power Company.
13 Issued by Gulf Power Capital Trust III and guaranteed by Gulf Power Company.
14 Issued by Mississippi Power Capital Trust I and guaranteed by Mississippi
Power Company.
15 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah
Electric and Power Company.
16 As of December 31, 2001.

<PAGE>



Preferred stock, cumulative, $100 par value       Gulf Power Company
4.64% Series      5.44% Series
5.16% Series

           ----------------------------------------------------------

Preferred stock, cumulative, $100 par value       Mississippi Power Company
4.40% Series     4.60% Series
4.72% Series     7.00% Series

           ----------------------------------------------------------

  Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No___

  Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ( )

             Aggregate market value of voting stock held by non-affiliates of
The Southern Company at February 28, 2002: $17.8 billion. Each of such other
registrants is a wholly-owned subsidiary of The Southern Company. A description
of registrants' common stock follows:
<TABLE>
<CAPTION>

                                                   Description of                      Shares Outstanding
Registrant                                          Common Stock                      at February 28, 2002
----------                                          ------------                      --------------------
<S>                                          <C>                                             <C>
The Southern Company                         Par Value $5 Per Share                          700,085,336
Alabama Power Company                        Par Value $40 Per Share                           6,000,000
Georgia Power Company                        No Par Value                                      7,761,500
Gulf Power Company                           No Par Value                                        992,717
Mississippi Power Company                    Without Par Value                                 1,121,000
Savannah Electric and Power Company          Par Value $5 Per Share                           10,844,635
</TABLE>


Documents incorporated by reference: specified portions of The Southern
Company's Proxy Statement relating to the 2002 Annual Meeting of Stockholders
are incorporated by reference into PART III. In addition, specified portions of
the Information Statements of Alabama Power Company, Georgia Power Company, Gulf
Power Company and Mississippi Power Company relating to each of their respective
2002 Annual Meeting of Shareholders are incorporated by reference into PART III.

This combined Form 10-K is separately filed by The Southern Company, Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company and Savannah Electric and Power Company. Information contained herein
relating to any individual company is filed by such company on its own behalf.
Each company makes no representation as to information relating to the other
companies.

===============================================================================
<PAGE>
<TABLE>
<CAPTION>



                                Table of Contents

                                                                                            Page
               PART I

Item 1          Business

               <C>                                                                         <C>
                  Mirant Corporation........................................................  I-1
                  The SOUTHERN System.......................................................  I-2
                  Operating Companies.......................................................  I-2
                  Southern Power............................................................  I-2
                  Other Business............................................................  I-3
                  Certain Factors Affecting the Industry....................................  I-3
                  Construction Programs.....................................................  I-4
                  Financing Programs........................................................  I-6
                  Fuel Supply...............................................................  I-7
                  Territory Served by the Operating Companies...............................  I-8
                  Competition...............................................................  I-11
                  Regulation................................................................  I-13
                  Rate Matters..............................................................  I-16
                  Employee Relations........................................................  I-18
Item 2          Properties..................................................................  I-20
Item 3          Legal Proceedings...........................................................  I-24
Item 4          Submission of Matters to a Vote of Security Holders.........................  I-27
                Executive Officers of SOUTHERN..............................................  I-28
                Executive Officers of ALABAMA...............................................  I-29
                Executive Officers of GEORGIA...............................................  I-30
                Executive Officers of GULF..................................................  I-31
                Executive Officers of MISSISSIPPI...........................................  I-32

                PART II

Item 5          Market for Registrants' Common Equity and Related Stockholder Matters.......  II-1
Item 6          Selected Financial Data.....................................................  II-2
Item 7          Management's Discussion and Analysis of Results of Operations
                  and Financial Condition...................................................  II-2
Item 7A         Quantitative and Qualitative Disclosures about Market Risk..................  II-2
Item 8          Financial Statements and Supplementary Data.................................  II-3
Item 9          Changes in and Disagreements with Accountants on
                  Accounting and Financial Disclosure.......................................  II-4

                PART III

Item 10         Directors and Executive Officers of the Registrants........................   III-1
Item 11         Executive Compensation.....................................................   III-3
Item 12         Security Ownership of Certain Beneficial Owners and
                  Management...............................................................   III-9
Item 13         Certain Relationships and Related Transactions.............................   III-10

                PART IV

Item 14         Exhibits, Financial Statement Schedules, and Reports
                  on Form 8-K..............................................................   IV-1

</TABLE>
                                       i
<PAGE>
<TABLE>
<CAPTION>
                                                           DEFINITIONS

 When used in Items 1 through 5 and Items 10 through 14, the following terms
will have the meanings indicated.

 Term                                                             Meaning

<S>                                                   <C>
 AEC...........................................       Alabama Electric Cooperative, Inc.
 AFUDC.........................................       Allowance for Funds Used During Construction
 ALABAMA.......................................       Alabama Power Company
 AMEA..........................................       Alabama Municipal Electric Authority
 Clean Air Act.................................       Clean Air Act Amendments of 1990
 Dalton........................................       City of Dalton, Georgia
 DOE...........................................       United States Department of Energy
 EMF...........................................       Electromagnetic field
 Energy Act....................................       Energy Policy Act of 1992
 Energy Solutions..............................       Southern Company Energy Solutions, Inc.
 Entergy Gulf States...........................       Entergy Gulf States Utilities Company
 EPA...........................................       United States Environmental Protection Agency
 FERC..........................................       Federal Energy Regulatory Commission
 FPC...........................................       Florida Power Corporation
 FP&L..........................................       Florida Power & Light Company
 GEORGIA.......................................       Georgia Power Company
 GULF..........................................       Gulf Power Company
 Holding Company Act...........................       Public Utility Holding Company Act of 1935, as amended
 IBEW..........................................       International Brotherhood of Electrical Workers
 IPP...........................................       Independent power producer
 IRP...........................................       Integrated Resource Plan
 IRS...........................................       Internal Revenue Service
 JEA...........................................       Jacksonville Electric Authority
 MEAG..........................................       Municipal Electric Authority of Georgia
 MESH..........................................       Mobile Energy Services Holdings
 Mirant........................................       Mirant Corporation (formerly Southern Energy, Inc.)
 MISSISSIPPI...................................       Mississippi Power Company
 NRC...........................................       Nuclear Regulatory Commission
 OPC...........................................       Oglethorpe Power Corporation
 operating companies...........................       ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
 PPA...........................................       Purchased Power Agreements
 PSC...........................................       Public Service Commission
 RFP...........................................       Request for Proposal
 RTO...........................................       Regional Transmission Organization
 RUS...........................................       Rural Utility Service (formerly Rural Electrification
                                                         Administration)
</TABLE>
                                       ii

<PAGE>
<TABLE>
<CAPTION>

                                               DEFINITIONS
                                               (continued)



 <S>                                                  <C>
 SAVANNAH......................................       Savannah Electric and Power Company
 SCS...........................................       Southern Company Services, Inc. (the system
                                                         service company)
 SEC...........................................       Securities and Exchange Commission
 SEGCO.........................................       Southern Electric Generating Company
 SEPA..........................................       Southeastern Power Administration
 SERC..........................................       Southeastern Electric Reliability Council
 SMEPA.........................................       South Mississippi Electric Power Association
 SOUTHERN......................................       The Southern Company
 Southern LINC.................................       Southern Communications Services, Inc.
 Southern Management Development...............       Southern Management Development, Inc.
 Southern Nuclear..............................       Southern Nuclear Operating Company, Inc.
 Southern Power................................       Southern Power Company
 SOUTHERN system...............................       SOUTHERN, the operating companies, Southern Power,
                                                        SEGCO, Southern Nuclear, SCS, Southern LINC, Energy Solutions
                                                        and other subsidiaries
 Southern Telecom..............................       Southern Telecom, Inc.
 TVA...........................................       Tennessee Valley Authority
</TABLE>

                                      iii

<PAGE>



                         CAUTIONARY STATEMENT REGARDING
                           FORWARD-LOOKING INFORMATION

    This Annual Report on Form 10-K contains forward-looking and historical
information. Forward-looking information includes, among other things,
statements concerning the strategic goals for SOUTHERN's new wholesale business
and also SOUTHERN's goals for dividend payout ratio, earnings per share and
earnings growth. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "could," "should," "expects," "plans,"
"anticipates," "believes," "estimates," "projects," "predicts," "potential" or
"continue" or the negative of these terms or other comparable terminology.
SOUTHERN cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which SOUTHERN
and its subsidiaries are subject, as well as changes in application of existing
laws and regulations; current and future litigation, including the pending EPA
civil action against certain SOUTHERN subsidiaries and the race discrimination
litigation against certain SOUTHERN subsidiaries; the effects, extent and timing
of the entry of additional competition in the markets in which SOUTHERN's
subsidiaries operate; the impact of fluctuations in commodity prices, interest
rates and customer demand; state and federal rate regulations; political, legal
and economic conditions and developments in the United States; the performance
of projects undertaken by the non-traditional business and the success of
efforts to invest in and develop new opportunities; internal restructuring or
other restructuring options that may be pursued; potential business strategies,
including acquisitions or dispositions of assets or businesses, which cannot be
assured to be completed or beneficial to SOUTHERN or its subsidiaries; the
effects of, and changes in, economic conditions in the areas in which SOUTHERN's
subsidiaries operate; the direct or indirect effects on SOUTHERN's business
resulting from the terrorist incidents on September 11, 2001, or any similar
such incidents or responses to such incidents; financial market conditions and
the results of financing efforts; the timing and acceptance of SOUTHERN's new
product and service offerings; the ability of SOUTHERN to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports filed from
time to time with the SEC.

                                       iv


<PAGE>

                                     PART I

Item 1.  BUSINESS

    SOUTHERN was incorporated under the laws of Delaware on November 9, 1945.
SOUTHERN is domesticated under the laws of Georgia and is qualified to do
business as a foreign corporation under the laws of Alabama. SOUTHERN owns all
the outstanding common stock of ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH, each of which is an operating public utility company. The operating
companies supply electric service in the states of Alabama, Georgia, Florida,
Mississippi and Georgia, respectively. More particular information relating to
each of the operating companies is as follows:

      ALABAMA is a corporation organized under the laws of the State of Alabama
      on November 10, 1927, by the consolidation of a predecessor Alabama Power
      Company, Gulf Electric Company and Houston Power Company. The predecessor
      Alabama Power Company had had a continuous existence since its
      incorporation in 1906.

      GEORGIA was incorporated under the laws of the State of Georgia on June
      26, 1930, and admitted to do business in Alabama on September 15, 1948.

      GULF is a corporation which was organized under the laws of the State of
      Maine on November 2, 1925, and admitted to do business in Florida on
      January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on
      November 20, 1984.

      MISSISSIPPI was incorporated under the laws of the State of Mississippi on
      July 12, 1972, was admitted to do business in Alabama on November 28,
      1972, and effective December 21, 1972, by the merger into it of the
      predecessor Mississippi Power Company, succeeded to the business and
      properties of the latter company. The predecessor Mississippi Power
      Company was incorporated under the laws of the State of Maine on November
      24, 1924, and was admitted to do business in Mississippi on December 23,
      1924, and in Alabama on December 7, 1962.

      SAVANNAH is a corporation existing under the laws of the State of Georgia;
      its charter was granted by the Secretary of State on August 5, 1921.

    SOUTHERN also owns all the outstanding common stock of Southern LINC,
Southern Nuclear, SCS, Southern Management Development (formerly Energy
Solutions), Southern Telecom, Southern Power and other direct and indirect
subsidiaries. Southern LINC provides digital wireless communications services to
SOUTHERN's operating companies and also markets these services to the public
within the Southeast. Southern Nuclear provides services to ALABAMA's and
GEORGIA's nuclear plants. Southern Management Development focuses on new and
existing programs to enhance customer satisfaction, efficiency and stockholder
value. Southern Telecom provides wholesale fiber optic solutions to
telecommunication providers in the Southeastern United States.

    In January 2001, SOUTHERN formed a new subsidiary, Southern Power. This
subsidiary constructs, owns and manages wholesale generating assets in the
Southeast. Southern Power will be the primary growth engine for SOUTHERN's
competitive wholesale market-based energy business.

    ALABAMA and GEORGIA each own 50% of the outstanding common stock of SEGCO.
SEGCO owns electric generating units with an aggregate capacity of 1,019,680
kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama, and
ALABAMA and GEORGIA are each entitled to one-half of SEGCO's capacity and
energy. ALABAMA acts as SEGCO's agent in the operation of SEGCO's units and
furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000
volt transmission lines extending from Plant Gaston to the Georgia state line at
which point connection is made with the GEORGIA transmission line system.

    Reference is made to Note 12 to the financial statements of SOUTHERN in Item
8 herein for additional information regarding SOUTHERN's segment and related
information.

Mirant Corporation

In April 2000, SOUTHERN announced an initial public offering of up to 19.9
percent of Mirant and its intentions to spin off the remaining ownership of
Mirant to SOUTHERN stockholders within 12 months of the initial stock offering.
On October 2, 2000, Mirant completed its initial public offering of 66.7 million

                                      I-1
<PAGE>

shares of common stock priced at $22 per share. This represented 19.7 percent of
the 338.7 million shares outstanding. As a result of the stock offering,
SOUTHERN recorded a $560 million increase in paid-in capital with no gain or
loss being recognized.

   On February 19, 2001, SOUTHERN's board of directors approved the spin off of
its remaining ownership of 272 million Mirant shares. On April 2, 2001, the
tax-free distribution of Mirant shares was completed at a ratio of approximately
0.4 for every share of SOUTHERN common stock held at record date.

   The distribution resulted in charges of approximately $3.2 billion and $0.4
billion to SOUTHERN's paid-in capital and retained earnings, respectively.

   As a result of the spin off, SOUTHERN's financial statements reflect Mirant's
results of operations, balance sheets and cash flows as discontinued operations.

The SOUTHERN System

Operating Companies

The transmission facilities of each of the operating companies are connected to
the respective company's own generating plants and other sources of power and
are interconnected with the transmission facilities of the other operating
companies and SEGCO by means of heavy-duty high voltage lines. (In the case of
GEORGIA's integrated transmission system, see Item 1 - BUSINESS - "Territory
Served by the Operating Companies" herein.)

    Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the operating companies have entered into voluntary reliability
agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy
Corporation, South Carolina Electric & Gas Company and Virginia Electric and
Power Company, each of which provides for the establishment and periodic review
of principles and procedures for planning and operation of generation and
transmission facilities, maintenance schedules, load retention programs,
emergency operations and other matters affecting the reliability of bulk power
supply. The operating companies have joined with other utilities in the
Southeast (including those referred to above) to form the SERC to augment
further the reliability and adequacy of bulk power supply. Through the SERC, the
operating companies are represented on the National Electric Reliability
Council.

    An intra-system interchange agreement provides for coordinating operations
of the power producing facilities of the operating companies and the capacities
available to such companies from non-affiliated sources and for the pooling of
surplus energy available for interchange. Coordinated operation of the entire
interconnected system is conducted through a central power supply coordination
office maintained by SCS. The available sources of energy are allocated to the
operating companies to provide the most economical sources of power consistent
with good operation. The resulting benefits and savings are apportioned among
the operating companies.

    SCS has contracted with SOUTHERN, each operating company, various of the
other subsidiaries, Southern Nuclear, Southern Power and SEGCO to furnish, at
cost and upon request, the following services: general executive and advisory
services, power pool operations, general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pensions, corporate, rates, budgeting, public
relations, human resources, systems and procedures and other services with
respect to business and operations and power pool operations. Southern
Management Development and Southern LINC have also secured from the operating
companies certain services which are furnished at cost.

    Southern Nuclear has contracts with ALABAMA to operate the Farley Nuclear
Plant, and with GEORGIA to operate Plants Hatch and Vogtle. See Item 1 -
BUSINESS - "Regulation - Atomic Energy Act of 1954" herein.

Southern Power

As stated above, Southern Power will be the primary growth engine for SOUTHERN's
competitive wholesale market-based energy business. Southern Power intends to
sell the output of its generating assets under long-term, market-based contracts

                                      I-2
<PAGE>

both to unaffiliated wholesale purchasers as well as the operating companies
(under power purchase agreements approved by the respective public service
commissions). Southern Power's wholesale generating assets will not be placed in
the operating companies' rate bases, and Southern Power will only be able to
recover costs from the operating companies based on the terms of the
market-based contracts for its wholesale generating assets. The market-based
contracts typically pass the cost of fuel to the wholesale energy purchasers and
reduce Southern Power's business risks, but its overall profit will depend on
the parameters of the wholesale market and its efficient operation of its
wholesale generating assets. By the end of 2003, Southern Power plans to have
approximately 4,700 megawatts of generating capacity in commercial operation. At
December 31, 2001, 800 megawatts were in commercial operation and some 3,900
megawatts of capacity are under construction.

Other Business

In March 2001, Energy Solutions changed its name to Southern Management
Development. Southern Management Development then created a separate entity,
Southern Company Energy Solutions LLC (SCES LLC) for its energy business. SCES
LLC provides energy related services such as energy outsourcing, energy
conservation, facility maintenance, energy management and turnkey services for
industrial, commercial, and governmental customers. Southern Management
Development focuses on new and existing programs to enhance customer
satisfaction, efficiency and stockholder value. Examples are: Bill Payment
Protection, an insurance product that protects a residential customer by paying
the electric bill in the event the customer becomes involuntarily unemployed,
disabled or goes on unpaid leave; and Electric Vehicle Chargers, a program to
supply electric vehicle charging units to industrial customers.

     In 1996, Southern LINC began serving SOUTHERN's operating companies and
marketing its services to non-affiliates within the Southeast. Its system covers
approximately 127,000 square miles and combines the functions of two-way radio
dispatch, cellular phone, short text and numeric messaging and wireless data
transfer.

    These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations. However, these activities also involve a higher degree of risk.
SOUTHERN expects to make substantial investments over the period 2002-2004 in
these and other new businesses.

     In 1999, MESH, a subsidiary of SOUTHERN, filed a petition for Chapter 11
bankruptcy relief in the U.S. Bankruptcy Court. On August 4, 2000, MESH filed a
proposed plan of reorganization with the U.S. Bankruptcy Court. The proposed
plan of reorganization was most recently amended on October 15, 2001. SOUTHERN
expects that approval of a plan of reorganization would result in either a
termination of SOUTHERN's ownership interest in MESH or the exchange of all
assets of MESH for the cancellation of securities held by the bondholders, but
would not affect SOUTHERN's continuing guarantee obligations. Reference is made
to Item 3 - "Legal Proceedings" herein for additional information relating to
this matter.

Certain Factors Affecting the Industry

Various factors are currently affecting the electric utility industry in
general, including increasing competition and the regulatory changes related
thereto, costs required to comply with environmental regulations and the
potential for new business opportunities (with their associated risks) outside
of traditional rate-regulated operations. The effects of these and other factors
on the SOUTHERN system are described herein. Particular reference is made to
Item 1 - BUSINESS - "Other Business", "Competition" and "Environmental
Regulation." See also "Cautionary Statement Regarding Forward-Looking
Information."

     In December 1999, the FERC issued its final rule on RTOs. The order
encouraged utilities owning transmission systems to form RTOs on a voluntary
basis. SOUTHERN has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
SOUTHERN explained that it is developing a for-profit RTO known as SeTrans with
a number of non-jurisdictional cooperative and public power entities. Recently,
Entergy Corporation and Cleco Power joined the SeTrans development process. In
January 2002, the sponsors of SeTrans held a public meeting to form a

                                      I-3
<PAGE>

Stakeholder Advisory Committee, which will participate in the development of the
RTO. SOUTHERN continues to work with the other sponsors to develop the SeTrans
RTO. The creation of SeTrans is not expected to have a material impact on
SOUTHERN's financial statements. The outcome of this matter cannot now be
determined.

Construction Programs

The subsidiary companies of SOUTHERN are engaged in continuous construction
programs to accommodate existing and estimated future loads on their respective
systems. Construction additions or acquisitions of property during 2002 through
2004 by the operating companies, SEGCO, SCS, Southern LINC, Southern Power and
other subsidiaries are estimated as follows: (in millions)

 ------------------------------ -------- --------- ----------
                                   2002      2003      2004
                                -------- --------- ----------
 ALABAMA                         $  671  $    592      $673
 GEORGIA                            971       752       809
 GULF                               103        72       107
 MISSISSIPPI                         84        72        85
 SAVANNAH                            35        38        43
 SEGCO                               15        17        23
 SCS                                 27        23        25
 Southern LINC                       29        28        23
 Southern Power                     834       488       473
 Other                               29        14         2
 --------------------------- ----------- --------- ----------
 SOUTHERN system                 $2,798    $2,096  $  2,263
 =========================== =========== ========= ==========


                                      I-4
<PAGE>


<TABLE>
<CAPTION>



Estimated construction costs in 2002 are expected to be apportioned approximately as follows: (in millions)



 ---------------------------- --------------- --------------- ------------- --------- --------------- ---------------- ------------
                              SOUTHERN                                                                                    Southern
                                system*       ALABAMA         GEORGIA       GULF       MISSISSIPPI           SAVANNAH      Power
                              --------------- --------------- ------------- --------- --------------- ---------------- ------------
<S>                               <C>             <C>               <C>       <C>          <C>              <C>              <C>
 New generation                   $  833          $  -              $  -      $24          $-               $-               $809
 Other generating
    facilities including
    associated plant
    substations                      703           248               383       24           25                8                -
 New business                        365           127               182       23           15               18                -
 Transmission                        378           141               210        9           16                2                -
 Joint line and substation            55             -                45        7            3                -                -
 Distribution                        162            68                61       10           17                6                -
 Nuclear fuel                        123            63                60        -            -                -                -
 General plant                       179            24                30        6            8                1               25
                              --------------- --------------- ------------- --------- --------------- ---------------- ------------
                                  $2,798          $671              $971     $103          $84              $35             $834
                              =============== =============== ============= ========= =============== ================ ============
</TABLE>

    * SCS, Southern LINC and other businesses plan capital additions to general
plant in 2002 of $27 million, $29 million and $29 million, respectively, while
SEGCO plans capital additions of $15 million to generating facilities. (See Item
1 - BUSINESS - "Other Business" herein.)

    The construction programs are subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include: changes in business conditions; acquisitions of
additional generating assets; revised load growth estimates; changes in
environmental regulations; changes in existing nuclear plants to meet new
regulatory requirements; increasing costs of labor, equipment and materials; and
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered.

    SOUTHERN has approximately 4,500 megawatts of new generating capacity
scheduled to be placed in service by 2003. Approximately 3,900 megawatts of
additional new capacity will be dedicated to the wholesale market and owned by
Southern Power. Significant construction of transmission and distribution
facilities and upgrading of generating plants will be continuing.

    Under Georgia law, GEORGIA and SAVANNAH each are required to file an
Integrated Resource Plan for approval by the Georgia PSC. Under the plan rules,
the Georgia PSC must pre-certify the construction of new power plants and new
purchase power contracts. (See Item 1 - BUSINESS - "Rate Matters - Integrated
Resource Planning" herein.)

    See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein for
information with respect to certain existing and proposed environmental
requirements and Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein for
additional information concerning ALABAMA's, GEORGIA's and Southern Power's
joint ownership of certain generating units and related facilities with certain
non-affiliated utilities.


                                      I-5


<PAGE>


Financing Programs

The amount and timing of additional equity capital to be raised in 2002, as well
as in subsequent years, will be contingent on SOUTHERN's investment
opportunities. Equity capital can be provided from any combination of public
offerings, private placements or SOUTHERN's stock plans.

    The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources and by the issuances of new debt and preferred
equity securities, term loans and short-term borrowings. However, the type and
timing of any financings -- if needed -- will depend on market conditions and
regulatory approval. In recent years, financings primarily have utilized
unsecured debt and trust preferred securities.

    Southern Power will use both external funds and equity capital from SOUTHERN
to finance its construction program. In addition, Southern Power has an $850
million revolving credit facility which extends through November 2004.

    Short-term debt is often utilized as appropriate at SOUTHERN, the operating
companies, SEGCO and Southern Power.

    The maximum amounts of short-term and term-loan indebtedness authorized by
the appropriate regulatory authorities are shown on the following table:

                      Amount          Outstanding at
                    Authorized       December 31, 2001
                   --------------    ---------------------
                             (in millions)
  ALABAMA              $1,000(1)              $ 10
  GEORGIA               1,700(2)               748
  GULF                    300(1)                87
  MISSISSIPPI             350(1)                16
  SAVANNAH                205(2)                32
  Southern Power        2,500(3)                 1
  SOUTHERN              2,000(1)               950
  ------------------- ------------- -- -------------------

Notes:

    (1) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 2003. No SEC authorization is required for
ALABAMA. GULF, MISSISSIPPI and SOUTHERN have received SEC authorization to issue
from time to time short-term and/or term-loan notes to banks and commercial
paper to dealers in the amounts shown through December 31, 2003, December 31,
2002 and December 31, 2004, respectively.

    (2) GEORGIA and SAVANNAH have received SEC authorization to issue from time
to time short-term and term-loan notes to banks and commercial paper to dealers
in the amounts shown through December 31, 2002. Authorization for term-loan
indebtedness is also required by the Georgia PSC. SAVANNAH received authority
from the Georgia PSC for $115 million in term loans expiring December 31, 2003.
As a part of a financing request from the Georgia PSC, GEORGIA has asked for
financing authority of $1.765 billion in term loans.

    (3) Southern Power has been authorized by the SEC to enter into various
financing arrangements, including short-term loans, through June 30, 2005, which
in the aggregate may not exceed $2.5 billion.

    Reference is made to Note 8 to the financial statements for SOUTHERN, Note 8
to the financial statements for ALABAMA, GULF and MISSISSIPPI and Note 6 to the
financial statements for SAVANNAH and Note 9 to the financial statements for
GEORGIA in Item 8 herein for information regarding the registrants' bank credit
arrangements.


                                      I-6
<PAGE>


Fuel Supply

The operating companies' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1999 through
2001 are shown below:
                                                   Oil and
 ALABAMA               Coal    Nuclear    Hydro       Gas
                     --------- ---------- --------- ---------
            1999        72       20         5         3
            2000        72       19         3         6
            2001        64       18         6        12

 GEORGIA
            1999        75       22         1         2
            2000        76       21         1         2
            2001        75       23         1         1

 GULF
            1999        97       **        **         3
            2000        98       **        **         2
            2001        99       **        **         1

 MISSISSIPPI
            1999        81       **        **        19
            2000        83       **        **        17
                              **
            2001        59       **        **        41

 SAVANNAH
            1999        78       **        **        22
            2000        88       **        **        12
            2001        93       **        **         7

 SEGCO
            1999       100       **        **         *
            2000       100       **        **         *
            2001       100       **        **         *

 SOUTHERN system***
            1999       78        17         2         3
            2000       78        16         2         4
            2001       72        16         3         9
 ---------- ------- --------- ---------- --------- ---------
    *Less than 0.5%.
  **Not applicable.
***  Amounts shown for the SOUTHERN system are weighted averages of the
     operating companies, Southern Power and SEGCO.

    The average costs of fuel in cents per net kilowatt-hour generated for 1999
through 2001 are shown below:

                        1999           2000          2001
                     -------------- ------------- -------------


ALABAMA                 1.44           1.54          1.56

GEORGIA                 1.34           1.39          1.38

GULF                    1.60           1.68          1.76

MISSISSIPPI             1.65           1.80          1.89

SAVANNAH                2.20           2.28          2.16

SEGCO                   1.77           1.51          1.44

SOUTHERN
    System*             1.45           1.51          1.56
------------------- -------------- ------------- -------------
* Amounts shown for the SOUTHERN system are weighted averages of the operating
companies, Southern Power and SEGCO.


                                      I-7
<PAGE>

    The operating companies have long-term agreements in place from which they
expect to receive approximately 78% of their coal burn requirements in 2002.
These agreements cover remaining terms up to 9 years. In 2001, the weighted
average sulfur content of all coal burned by the operating companies was 0.76%
sulfur. This sulfur level, along with banked sulfur dioxide allowances, allowed
the operating companies to remain within limits as set forth by Phase II of the
Clear Air Act. As more and more strict environmental regulations are proposed
that impact the utilization of coal, the fuel mix will be monitored to insure
that sufficient quantities of the proper type of coal or natural gas are in
place to remain in compliance with applicable laws and regulations. See Item 1 -
BUSINESS - "Regulation - Environmental Regulation" herein.

    The operating companies and Southern Power also have long-term agreements in
place for their natural gas burn requirements. For 2002, the operating companies
and Southern Power have contracted for 163.6 billion cubic feet of natural gas
supply. These agreements cover remaining terms up to 5 years. In addition to gas
supply, the operating companies have contracts in place for both firm gas
transportation and firm gas storage. Management believes that these contracts
provide sufficient natural gas supplies, transportation and storage to ensure
normal operations of the SOUTHERN system's natural gas generating units.

    Changes in fuel prices are generally reflected in fuel adjustment clauses
contained in rate schedules. See Item 1 - BUSINESS - "Rate Matters - Rate
Structure" herein.

    ALABAMA and GEORGIA have numerous contracts covering a portion of their
nuclear fuel needs for uranium, conversion services, enrichment services and
fuel fabrication. These contracts have varying expiration dates and most are
short to medium term (less than 10 years). Management believes that sufficient
capacity for nuclear fuel supplies and processing exists to preclude the
impairment of normal operations of the SOUTHERN system's nuclear generating
units.

    ALABAMA and GEORGIA have contracts with the DOE that provide for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent fuel in January 1998, as required by the contracts, and the companies are
pursuing legal remedies against the government for breach of contract.
Sufficient pool storage capacity is available at Plant Farley to maintain
full-core discharge capability until the refueling outages scheduled for 2006
and 2008 for units 1 & 2, respectively. Sufficient pool storage capacity
currently for spent fuel is available at Plant Vogtle to maintain full-core
discharge capability for both units into 2014. To maintain pool discharge
capability at Plant Hatch, effective June 2000, an on-site dry storage facility
became operational. Sufficient dry storage capacity is believed to be available
to continue dry storage operations at Plant Hatch through the life of the plant.
Procurement of on-site dry storage capacity at Plant Vogtle will begin in
sufficient time to maintain pool full-core discharge capability.

    The Energy Act required the establishment of a Uranium Enrichment
Decontamination and Decommissioning Fund, which is funded in part by a special
assessment on utilities with nuclear plants, including ALABAMA and GEORGIA. This
assessment is being paid over a 15-year period which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will recover
these payments in the same manner as any other fuel expense.

Territory Served by the Operating Companies

The territory in which the operating companies provide electric service
comprises most of the states of Alabama and Georgia together with the
northwestern portion of Florida and southeastern Mississippi. In this territory
there are non-affiliated electric distribution systems which obtain some or all
of their power requirements either directly or indirectly from the operating
companies. The territory has an area of approximately 120,000 square miles and
an estimated population of approximately 11 million.

    ALABAMA is engaged, within the State of Alabama, in the generation and
purchase of electricity and the distribution and sale of such electricity at
retail in over 1,000 communities (including Anniston, Birmingham, Gadsden,
Mobile, Montgomery and Tuscaloosa) and at wholesale to 15 municipally-owned
electric distribution systems, 11 of which are served indirectly through sales
to AMEA, and two rural distributing cooperative associations. ALABAMA also

                                      I-8
<PAGE>

supplies steam service in downtown Birmingham. ALABAMA also sells, and
cooperates with dealers in promoting the sale of, electric appliances.

    GEORGIA is engaged in the generation and purchase of electricity and the
distribution and sale of such electricity within the State of Georgia at retail
in over 600 communities, as well as in rural areas, and at wholesale currently
to OPC, MEAG, Dalton and the City of Hampton.

    GULF is engaged, within the northwestern portion of Florida, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail in 71 communities (including Pensacola, Panama City and
Fort Walton Beach), as well as in rural areas, and at wholesale to a
non-affiliated utility and a municipality.

    MISSISSIPPI is engaged in the generation and purchase of electricity and the
distribution and sale of such energy within the 23 counties of southeastern
Mississippi, at retail in 123 communities (including Biloxi, Gulfport,
Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and at
wholesale to one municipality, six rural electric distribution cooperative
associations and one generating and transmitting cooperative.

    SAVANNAH is engaged, within a five-county area in eastern Georgia, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail and, as a member of the SOUTHERN system power pool, the
transmission and sale of wholesale energy.

    For information relating to kilowatt-hour sales by classification for each
registrant, reference is made to "Management's Discussion and Analysis-Results
of Operations" in Item 7 herein. Also, for information relating to the sources
of revenues for the SOUTHERN system and each of the operating companies,
reference is made to Item 6 herein.

    A portion of the area served by the operating companies adjoins the area
served by TVA and its municipal and cooperative distributors. An Act of Congress
limits the distribution of TVA power, unless otherwise authorized by Congress,
to specified areas or customers which generally were those served on July 1,
1957.

    The RUS has authority to make loans to cooperative associations or
corporations to enable them to provide electric service to customers in rural
sections of the country. There are 71 electric cooperative organizations
operating in the territory in which the operating companies provide electric
service at retail or wholesale.

    One of these, AEC, is a generating and transmitting cooperative selling
power to several distributing cooperatives, municipal systems and other
customers in south Alabama and northwest Florida. AEC owns generating units with
approximately 840 megawatts of nameplate capacity, including an undivided
ownership interest in ALABAMA's Plant Miller Units 1 and 2. AEC's facilities
were financed with RUS loans secured by long-term contracts requiring
distributing cooperatives to take their requirements from AEC to the extent such
energy is available. Two of the 14 distributing cooperatives operating in
ALABAMA's service territory obtain a portion of their power requirements
directly from ALABAMA.

    Four electric cooperative associations, financed by the RUS, operate within
GULF's service area. These cooperatives purchase their full requirements from
AEC and SEPA (a federal power marketing agency). A non-affiliated utility also
operates within GULF's service area and purchases its full requirements from
GULF.

    ALABAMA and GULF have entered into separate agreements with AEC involving
interconnection between the respective systems. The delivery of capacity and
energy from AEC to certain distributing cooperatives in the service areas of
ALABAMA and GULF is governed by the SOUTHERN/AEC Network Transmission Service
Agreement. The rates for this service to AEC are based on the negotiated
agreement on file with the FERC. See Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein for details of ALABAMA's joint-ownership with AEC of a
portion of Plant Miller.

    MISSISSIPPI has an interchange agreement with SMEPA, a generating and
transmitting cooperative, pursuant to which various services are provided,
including the furnishing of protective capacity by MISSISSIPPI to SMEPA. SMEPA
has a generating capacity of 1,947 megawatts and a transmission system estimated
to be 1,549 miles in length.

                                      I-9
<PAGE>

    There are 43 electric cooperative organizations operating in, or in areas
adjoining, territory in the State of Georgia in which GEORGIA provides electric
service at retail or wholesale. Three of these organizations obtain their power
from TVA and one from other sources. OPC has a wholesale power contract with the
remaining 39 of these cooperative organizations. OPC utilizes self-owned
generation acquired from GEORGIA, megawatt capacity purchases from GEORGIA under
power supply agreements, and other arrangements to meet its power supply
obligations. Pursuant to the latest agreement entered into in April 1999, OPC
will purchase 250 megawatts of steam capacity through March 2006.

    There are 65 municipally-owned electric distribution systems operating in
the territory in which the operating companies provide electric service at
retail or wholesale.

    AMEA was organized under an act of the Alabama legislature and is comprised
of 11 municipalities. In 1986, ALABAMA entered into a firm power sales contract
with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum of 100
megawatts) for a period of 15 years (1986 Contract). In October 1991, ALABAMA
entered into a second firm power purchase contract with AMEA entitling AMEA to
scheduled amounts of additional capacity (to a maximum 80 megawatts) for a
period of 15 years (1991 Contract). Under the terms of the contracts, ALABAMA
received payments from AMEA representing the net present value of the revenues
associated with the respective capacity entitlements. The 1986 Contract expired
in July 2001, however, the payments for the 1991 Contract will continue as
scheduled capacity is made available over the terms of the 1991 Contract. See
Note 6 to ALABAMA's financial statements in Item 8 herein for further
information on these contracts.

    Forty-eight municipally-owned electric distribution systems and one
county-owned system receive their requirements through MEAG, which was
established by a state statute in 1975. MEAG serves these requirements from
self-owned generation facilities acquired from GEORGIA, power purchased from
GEORGIA and purchases from other resources. In August 1997, a pseudo scheduling
and services agreement was implemented between GEORGIA and MEAG that replaced
the partial requirements tariff pursuant to which GEORGIA previously sold
wholesale energy to MEAG. Since 1977, Dalton has filled its requirements from
self-owned generation facilities acquired from GEORGIA and through purchases
from GEORGIA pursuant to their partial requirements tariff. One
municipally-owned electric distribution system's full requirements are served
under a market-based contract by GEORGIA. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.)

     GEORGIA has entered into substantially similar agreements with Georgia
Transmission Corporation (formerly OPC's transmission division), MEAG and Dalton
providing for the establishment of an integrated transmission system to carry
the power and energy of each. The agreements require an investment by each party
in the integrated transmission system in proportion to its respective share of
the aggregate system load. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities"
herein.)

     SCS, acting on behalf of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH,
also has a contract with SEPA providing for the use of those companies'
facilities at government expense to deliver to certain cooperatives and
municipalities, entitled by federal statute to preference in the purchase of
power from SEPA, quantities of power equivalent to the amounts of power
allocated to them by SEPA from certain United States government hydroelectric
projects.

    The retail service rights of all electric suppliers in the State of Georgia
are regulated by the 1973 State Territorial Electric Service Act. Pursuant to
the provisions of this Act, all areas within existing municipal limits were
assigned to the primary electric supplier therein on March 29, 1973 (451
municipalities, including Atlanta, Columbus, Macon, Augusta, Athens, Rome and
Valdosta, to GEORGIA; 115 to electric cooperatives; and 50 to publicly-owned
systems). Areas outside of such municipal limits were either to be assigned or
to be declared open for customer choice of supplier by action of the Georgia PSC
pursuant to standards set forth in the Act. Consistent with such standards, the
Georgia PSC has assigned substantially all of the land area in the state to a
supplier. Notwithstanding such assignments, the Act provides that any new
customer locating outside of 1973 municipal limits and having a connected load
of at least 900 kilowatts may receive electric service from the supplier of its
choice. (See also Item 1 - BUSINESS - "Competition" herein.)

                                      I-10
<PAGE>

     Under and subject to the provisions of its franchises and concessions and
the 1973 State Territorial Electric Service Act, SAVANNAH has the full but
nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale,
Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee
Island, Springfield, Thunderbolt and Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been
assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and
Screven Counties by the Georgia PSC. (See also Item 1 - BUSINESS - "Competition"
herein.)

     Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather
Certificates" of public convenience and necessity to MISSISSIPPI and to six
distribution rural cooperatives operating in southeastern Mississippi, then
served in whole or in part by MISSISSIPPI, authorizing them to distribute
electricity in certain specified geographically described areas of the state.
The six cooperatives serve approximately 300,000 retail customers in a
certificated area of approximately 10,300 square miles. In areas included in a
"Grandfather Certificate," the utility holding such certificate may, without
further certification, extend its lines up to five miles; other extensions
within that area by such utility, or by other utilities, may not be made except
upon a showing of, and a grant of a certificate of, public convenience and
necessity. Areas included in such a certificate which are subsequently annexed
to municipalities may continue to be served by the holder of the certificate,
irrespective of whether it has a franchise in the annexing municipality. On the
other hand, the holder of the municipal franchise may not extend service into
such newly annexed area without authorization by the Mississippi PSC.

Long-Term Power Sales and Lease Agreements

The operating companies have long-term contractual agreements for the sale and
lease of capacity to certain non-affiliated utilities located outside the
SOUTHERN system service area. These agreements are firm and related to specific
generating units. Because the energy is generally provided at cost under these
agreements, profitability is primarily affected by capacity revenues.

    Unit power from specific generating plants is currently being sold to FP&L,
FPC and JEA. Under these agreements, approximately 1,500 megawatts of capacity
is scheduled to be sold annually unless reduced by FP&L, FPC and JEA for the
periods after 2001 with a minimum of three years notice, until the expiration of
the contracts in 2010.

    Southern Power and MISSISSIPPI have operating leases for portions of their
generating unit capacity.

    Reference is made to Note 5 to the financial statements for SOUTHERN; Note 6
to the financial statements for ALABAMA, GULF and MISSISSIPPI and Note 7 to the
financial statements for GEORGIA in Item 8 herein for additional information
regarding contracts for the sales and lease of capacity and energy to
non-territorial customers.

Competition

The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Act. The Energy Act allows IPPs to access a utility's
transmission network in order to sell electricity to other utilities. This
enhances the incentive for IPPs to build cogeneration plants for a utility's
large industrial and commercial customers and sell energy generation to other
utilities. Also, electricity sales for resale rates are affected by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.

     Although the Energy Act does not permit retail customer access, it has been
a major catalyst for the recent restructuring and consolidations taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages that promote wholesale and retail competition. Among other
things, these initiatives allow customers to choose their electricity provider.
Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been discussed in Alabama,
Florida, Georgia and Mississippi, none have been enacted. Enactment would
require numerous issues to be resolved, including significant ones relating to
recovery of any stranded investments, full cost recovery of energy produced and

                                      I-11
<PAGE>

other issues related to the energy crisis that occurred in California. As a
result of that crisis, many states have either discontinued or delayed
implementation of initiatives involving retail deregulation.

     Reference is made to Item 1 - BUSINESS - "Certain Factors Affecting the
Industry" herein for information relating to SOUTHERN's RTO filing with the
FERC.

     Continuing to be a low-cost producer could provide opportunities to
increase market share and profitability in markets that evolve with changing
regulation. Conversely, if SOUTHERN's electric utilities do not remain low-cost
producers and provide quality service, then energy sales growth could be
limited, and this could significantly erode earnings. Reference is made to
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, "Management's Discussion and
Analysis - Future Earnings Potential" in Item 7 herein for further discussion of
rate matters.

     To adapt to a less regulated, more competitive environment, SOUTHERN
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets or some combination thereof.
Furthermore, SOUTHERN may engage in new business ventures that arise from
competitive and regulatory changes in the utility industry. Pursuit of any of
the above strategies, or any combination thereof, may significantly affect the
business operations and financial condition of SOUTHERN. (See Item 1 - BUSINESS
- "Southern Power" and "Other Business" herein.)

     As a result of the foregoing factors, SOUTHERN has experienced increasing
competition for available off-system sales of capacity and energy from
neighboring utilities and alternative sources of energy. Additionally, the
future effect of cogeneration and small-power production facilities on the
SOUTHERN system cannot currently be determined but may be adverse.

     SOUTHERN is working to maintain and expand its share of wholesale energy
sales in the Southeastern power markets. In January 2001, SOUTHERN formed a new
subsidiary - Southern Power. This subsidiary constructs, owns and manages
wholesale generating assets in the Southeast. Southern Power will be the primary
growth engine for SOUTHERN's competitive wholesale market-based energy business.
By the end of 2003, Southern Power plans to have approximately 4,700 megawatts
of generating capacity in commercial operation. At December 31, 2001, 800
megawatts were in commercial operation and some 3,900 megawatts of capacity are
under construction.

     ALABAMA currently has cogeneration contracts in effect with 10 industrial
customers. Under the terms of these contracts, ALABAMA purchases excess
generation of such companies. During 2001, ALABAMA purchased approximately 154
million kilowatt-hours from such companies at a cost of $5.5 million.

     GEORGIA currently has contracts in effect with nine small power producers
whereby GEORGIA purchases their excess generation. During 2001, GEORGIA
purchased 13.6 million kilowatt-hours from such companies at a cost of $355,000.
GEORGIA has purchased power agreements for electricity with two cogeneration
facilities. Payments are subject to reductions for failure to meet minimum
capacity output. During 2001, GEORGIA purchased 621.7 million kilowatt-hours at
a cost of $52.3 million from these facilities. Reference is made to Note 4 to
the financial statements for GEORGIA in Item 8 herein for information regarding
purchased power commitments.

     GULF currently has agreements in effect with four industrial customers
pursuant to which GULF purchases "as available" energy from customer-owned
generation. During 2001, GULF purchased 114 million kilowatt-hours from such
companies for $3.4 million.

     SAVANNAH currently has cogeneration contracts in effect with four large
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 2001, SAVANNAH purchased 41.2 million
kilowatt-hours from such companies at a cost of $1.4 million.

     The competition for retail energy sales among competing suppliers of energy
is influenced by various factors, including price, availability, technological
advancements and reliability. These factors are, in turn, affected by, among
other influences, regulatory, political and environmental considerations,
taxation and supply.


                                      I-12
<PAGE>

     The operating companies have experienced, and expect to continue to
experience, competition in their respective retail service territories in
varying degrees as the result of self-generation (as described above) and fuel
switching by customers and other factors. (See also Item 1 - BUSINESS -
"Territory Served by the Operating Companies" herein for information concerning
suppliers of electricity operating within or near the areas served at retail by
the operating companies.)

Regulation

State Commissions

The operating companies are subject to the jurisdiction of their respective
state regulatory commissions, which have broad powers of supervision and
regulation over public utilities operating in the respective states, including
their rates, service regulations, sales of securities (except for the
Mississippi PSC) and, in the cases of the Georgia PSC and Mississippi PSC, in
part, retail service territories. (See Item 1 - BUSINESS - "Rate Matters" and
"Territory Served by the Operating Companies" herein.)

Holding Company Act

SOUTHERN is registered as a holding company under the Holding Company Act, and
it and its subsidiary companies are subject to the regulatory provisions of said
Act, including provisions relating to the issuance of securities, sales and
acquisitions of securities and utility assets, services performed by SCS and
Southern Nuclear and the activities of certain of SOUTHERN's other subsidiaries.

     While various proposals have been introduced in Congress regarding the
Holding Company Act, the prospects for legislative reform or repeal are
uncertain at this time.

Federal Power Act

The Federal Power Act subjects the operating companies, Southern Power and SEGCO
to regulation by the FERC as companies engaged in the transmission or sale at
wholesale of electric energy in interstate commerce, including regulation of
accounting policies and practices.

     ALABAMA and GEORGIA are also subject to the provisions of the Federal Power
Act or the earlier Federal Water Power Act applicable to licensees with respect
to their hydroelectric developments. Among the hydroelectric projects subject to
licensing by the FERC are 14 existing ALABAMA generating stations having an
aggregate installed capacity of 1,593,600 kilowatts and 18 existing GEORGIA
generating stations having an aggregate installed capacity of 1,074,696
kilowatts.

     GEORGIA started the relicensing process for the Middle Chattahoochee
Project in 1998. This project consists of the Goat Rock, Oliver and North
Highlands facilities.

     GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity
which began commercial operation in 1995. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.)

     Licenses for all projects, excluding those discussed above, expire in the
period 2007-2033 in the case of ALABAMA's projects and in the period 2005-2039
in the case of GEORGIA's projects.

     Upon or after the expiration of each license, the United States Government,
by act of Congress, may take over the project or the FERC may relicense the
project either to the original licensee or to a new licensee. In the event of
takeover or relicensing to another, the original licensee is to be compensated
in accordance with the provisions of the Federal Power Act, such compensation to
reflect the net investment of the licensee in the project, not in excess of the
fair value of the property taken, plus reasonable damages to other property of
the licensee resulting from the severance therefrom of the property taken.

Atomic Energy Act of 1954

ALABAMA, GEORGIA and Southern Nuclear are subject to the provisions of the
Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over
the construction and operation of nuclear reactors, particularly with regard to
certain public health and safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a facility licensed under the Atomic
Energy Act of 1954, as amended.


                                      I-13
<PAGE>

     NRC operating licenses currently expire in June 2017 and March 2021 for
Plant Farley units 1 and 2, respectively, and in January 2027 and February 2029
for Plant Vogtle units 1 and 2, respectively. In January 2002, the NRC granted
GEORGIA a 20-year extension of the licenses for both units at Plant Hatch which
permits the operation of units 1 and 2 until 2034 and 2038, respectively.

     Reference is made to Notes 1 and 10 to
SOUTHERN's financial statements, Notes 1 and 9 to ALABAMA's financial statements
and Notes 1 and 5 to GEORGIA's financial statements in Item 8 herein for
information on nuclear decommissioning costs and nuclear insurance.
Additionally, Note 3 to GEORGIA's financial statements contains information
regarding nuclear performance standards imposed by the Georgia PSC that may
impact retail rates.

Environmental Regulation

The operating companies' and SEGCO's operations are subject to federal, state
and local environmental requirements which, among other things, control
emissions of particulates, sulfur dioxide and nitrogen oxides into the air; the
use, transportation, storage and disposal of hazardous and toxic waste; and
discharges of pollutants, including thermal discharges, into waters of the
United States. The operating companies and SEGCO expect to comply with such
requirements, which generally are becoming increasingly stringent, through
technical improvements, the use of appropriate combinations of low-sulfur fuel
and chemicals, addition of environmental control facilities, changes in control
techniques and reduction of the operating levels of generating facilities.
Failure to comply with such requirements could result in the complete shutdown
of individual facilities not in compliance as well as the imposition of civil
and criminal penalties.

     In November 1990, the Clean Air Act was signed into law. Title IV of the
Clean Air Act - the acid rain compliance provision of the law - significantly
affected SOUTHERN. Reductions in sulfur dioxide and nitrogen oxide emissions
from fossil-fired generating plants were required in two phases. Phase I
compliance began in 1995. SOUTHERN achieved Phase I compliance at its affected
plants by primarily switching to low-sulfur coal and with some equipment
upgrades. Construction expenditures for Phase I nitrogen oxide and sulfur
dioxide emissions compliance totaled approximately $300 million. Phase II sulfur
dioxide compliance was required in 2000. SOUTHERN used emission allowances and
fuel switching to comply with Phase II requirements. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits and ozone non-attainment requirements for
metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone
non-attainment requirements increased total construction expenditures through
2000 by approximately $100 million.

     Respective state plans to address the one-hour ozone non-attainment
standards for the Atlanta and Birmingham areas have been established and must be
implemented in May 2003. Seven generating plants in the Atlanta area and two
plants in the Birmingham area will be affected. Construction expenditures for
compliance with these new rules are currently estimated at approximately $940
million, of which $520 million remains to be spent.

     A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provision. However, there can be no assurance that
all Clean Air Act costs will be recovered.

     In July 1997, the EPA revised the national ambient air quality standards
for ozone and particulate matter. This revision made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA. In addition, the Federal District of
Columbia Circuit Court of Appeals is considering other legal challenges to these
standards. A court decision is expected in the spring of 2002. If the standards
are eventually upheld, implementation could be required by 2007 to 2010.

     In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rule affects 21 states, including
Alabama and Georgia. Compliance is required by May 31, 2004, for most states,
including Alabama. For Georgia, further rulemaking was required, and proposed

                                      I-14


<PAGE>

compliance was delayed until May 1, 2005. Additional construction expenditures
for compliance with these new rules are currently estimated at approximately
$190 million.

     In December 2000, having completed its utility studies for mercury and
other hazardous air pollutants (HAPS), the EPA issued a determination that an
emission control program for mercury and, perhaps, other HAPS is warranted. The
program is being developed under the Maximum Achievable Control Technology
provisions of the Clear Air Act, and the regulations are scheduled to be
finalized by the end of 2004 with implementation to take place around 2007. In
January 2001, the EPA proposed guidance for the determination of Best Available
Retrofit Technology (BART) emission controls under the Regional Haze
Regulations. Installation of BART controls is expected to take place around
2010. Litigation of the Regional Haze Regulations, including the BART
provisions, is ongoing in the Federal District of Columbia Circuit Court of
Appeals. A court decision is expected in mid-2002.

     Implementation of the final state rules for these initiatives could require
substantial further reduction in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emission from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.

     In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and the utility industry. Generally, this rule affects the operation and
maintenance of electrostatic precipitators and could involve significant
additional ongoing expense.

     The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.

     SOUTHERN must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the subsidiaries could incur substantial costs to clean up
properties. The subsidiaries conduct studies to determine the extent of any
required cleanup and have recognized in their respective financial statements
costs to clean up known sites. These costs for SOUTHERN amounted to $1 million
in 2001 and $4 million in both 2000 and 1999. Additional sites may require
environmental remediation for which the subsidiaries may be liable for a portion
or all required cleanup costs.

     Several major pieces of environmental legislation are periodically
considered for reauthorization or amendment by Congress. These include : the
Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response,
Compensation, and Liability Act; the Resource Conservation and Recovery Act; the
Toxic Substances Control Act; and the Endangered Species Act. Changes to these
laws could affect many areas of SOUTHERN's operations. The full impact of any
such changes cannot be determined at this time.

     Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect SOUTHERN. The impact of new legislation - if any -
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as a result of
lawsuits alleging damages caused by electromagnetic fields.

     Reference is made to each registrant's "Management's Discussion and
Analysis" in Item 7 herein for a discussion of the Clean Air Act and other
environmental legislation and proceedings. Also see Item 3 - "Legal
Proceedings", herein for information about a lawsuit brought on behalf of the
EPA.

     The operating companies' and SEGCO's estimated capital expenditures for
environmental quality control

                                      I-15
<PAGE>


facilities for the years 2002, 2003 and 2004 are as follows:  (in millions)

 -----------------------------------------------------------
                              2002        2003       2004
                           ---------------------------------
 ALABAMA                     $157        $95       $112
 GEORGIA                      320         93         66
 GULF                           5         15         26
 MISSISSIPPI                    4          9          1
 SAVANNAH                       4          6          2
 SEGCO                          *          *          *
 ----------------------------------------------------------
     Total                   $490       $218       $207
 ===========================================================

     * Amounts are less than $1 million.

     The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)

     Additionally, each operating company and SEGCO has incurred costs for
environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis" in Item 7 herein for
information regarding the registrants' environmental remediation efforts. Also,
see Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
information regarding the identification of sites that may require environmental
remediation by GEORGIA.

     The operating companies and SEGCO are unable to predict at this time what
additional steps they may be required to take as a result of the implementation
of existing or future quality control requirements for air, water and hazardous
or toxic materials, but such steps could adversely affect system operations and
result in substantial additional costs.

     The outcome of the matters mentioned above under "Regulation" cannot now be
determined, except that these developments may result in delays in obtaining
appropriate licenses for generating facilities, increased construction and
operating costs, or reduced generation, the nature and extent of which, while
not determinable at this time, could be substantial.

Rate Matters

Rate Structure

The rates and service regulations of the operating companies are uniform for
each class of service throughout their respective service areas. Rates for
residential electric service are generally of the block type based upon
kilowatt-hours used and include minimum charges.

     Residential and other rates contain separate customer charges. Rates for
commercial service are presently of the block type and, for large customers, the
billing demand is generally used to determine capacity and minimum bill charges.
These large customers' rates are generally based upon usage by the customer
including those with special features to encourage off-peak usage. Additionally,
the operating companies are allowed by their respective PSCs to negotiate the
terms and compensation of service to large customers. Such terms and
compensation of service, however, are subject to final PSC approval. ALABAMA,
GEORGIA and SAVANNAH are allowed by state law to recover fuel and net purchased
energy costs through fuel cost recovery provisions which are adjusted to reflect
increases or decreases in such costs. GULF recovers from retail customers costs
of fuel, net purchased power, energy conservation and environmental compliance
through provisions which are adjusted to reflect increases or decreases in such
costs. GULF's recovery of these costs is based upon an annual projection - any
over/under recovery during such period is reflected in a subsequent annual
period with interest. With respect to MISSISSIPPI's retail rates, fuel and
purchased power costs are billed to such customers under the fuel adjustment
clause and energy costs management clause. The adjustment factors for
MISSISSIPPI's retail and wholesale rates are generally levelized based on the
estimated energy cost for the year, adjusted for any actual over/under
collection from the previous year. Revenues are adjusted for differences between
recoverable fuel costs and amounts actually recovered in current rates.

Rate Proceedings

Reference is made to MISSISSIPPI's "Management's Discussion and Analysis" in
Item 7 and to Note 3 to each registrant's financial statements in Item 8 herein
for a discussion of rate matters.

                                      I-16
<PAGE>

     In February 2002, MISSISSIPPI reached an agreement with certain of its
wholesale customers to increase its wholesale tariff rates effective June 2002.
MISSISSIPPI filed the settlement agreement with the FERC on March 5, 2002. The
FERC has 60 days to either set the issue for hearing with the proposed rates
subject to refund or let the new rates go into effect as filed. The agreement
results in an annual increase of approximately $10.5 million and the adoption of
an Energy Cost Management Clause similar to the one approved by MISSISSIPPI's
retail jurisdiction (see Note 1 to MISSISSIPPI's financial statements in Item 8
herein). In addition, MISSISSIPPI and its customers agreed that neither party
would seek a unilateral change to the new rates prior to December 31, 2003,
except for changes due to the operation of the fuel adjustment and energy cost
management clauses. Though the FERC has accepted settlement agreements as filed
in the past, the ultimate outcome of this matter before the FERC cannot now be
determined.

     On March 5, 2002, the Alabama PSC approved a revision to ALABAMA's rates
that provide for periodic adjustments based upon ALABAMA's earned return on
end-of-period retail common equity. This revision provides for an annual, rather
than quarterly, adjustment and imposes a 3 percent limit on any such annual
adjustment. A 2 percent increase in retail rates will become effective in April
2002 in accordance with the Rate Stabilization Equalization Plan. The return on
common equity range of 13.0 to 14.5 percent remains unchanged. The Alabama PSC
also accepted ALABAMA's proposal to lower the energy cost recovery factor for
the billing months April 2002 through December 2002.

Integrated Resource Planning

In July 2001, the Georgia PSC approved the GEORGIA and SAVANNAH 2001 Integrated
Resource Plan, which was filed on January 31, 2001. The plans specify how
GEORGIA and SAVANNAH each intends to meet the future electrical needs of its
customers through a combination of demand-side and supply-side resources. The
Georgia PSC must pre-certify these new resources. Once certified, all prudently
incurred construction costs and purchase power costs will be recoverable through
rates.

     In July 2001, the Georgia PSC approved GEORGIA's 2003/04 certification
request, which was filed December 15, 2000, for approximately 1,800 megawatts of
purchased power and 12 megawatts of upgraded hydro generation. This
certification request included a seven-year PPA with Southern Power for two
gas-fired combined cycle units that will be constructed at Plant Goat Rock. The
first unit is designed to produce approximately 570 megawatts starting in 2003,
with approximately 370 megawatts being available by June 2002. The second unit
is designed to produce approximately 610 megawatts starting in 2004, with
approximately 400 megawatts being available by June 2003. Also, a capacity
upgrade of 12 megawatts was approved for the existing Goat Rock hydro units 1
and 2. In addition, this certification request included a seven-year PPA with
Southern Power for a gas fired combined cycle generating unit to be constructed
at Plant Autaugaville in Alabama. The unit is designed to produce approximately
610 megawatts starting in 2004. Based on an agreement with the Georgia PSC, the
seven-year term of the PPA was modified to be 15 years.

     In April 2001, GEORGIA and SAVANNAH issued an RFP for their 2005/06
resource needs of approximately 2,500 megawatts. At the request of the Georgia
PSC, this RFP requested all types of generation resources including coal and
nuclear. The bids received from this RFP totaled more than 25,000 megawatts
including over 1,800 megawatts of coal offers. As required by the Georgia PSC's
2001 IRP order, GEORGIA developed a self-build coal offer to be compared to the
bid received through the RFP. In conjunction with the Georgia PSC, an economic
analysis of the coal proposals was completed and the results indicated that the
coal resources were not economical as compared to gas-fired generation at this
point in time. Therefore, the Georgia PSC relieved GEORGIA of its obligation to
continue to develop a coal self-build proposal. At the present time, the bids
from this RFP are being analyzed and the best-cost projects will be selected.
Once the PPAs have been completed for the selected projects, GEORGIA and
SAVANNAH will file for certification of these PPAs by summer of 2002.
GEORGIA and SAVANNAH expect the Georgia PSC to approve the certification request
in the fall of 2002.

                                      I-17
<PAGE>


Environmental Cost Recovery Plans

In 1993, the Florida Legislature adopted legislation for an Environmental Cost
Recovery Clause (ECRC), which allows a utility, including GULF, to petition the
Florida PSC for recovery of prudent environmental compliance costs that are not
being recovered through base rates or any other recovery mechanism. Such
environmental costs include operation and maintenance expense, emission
allowance expense, depreciation and a return on invested capital.

     In 1992, the Mississippi PSC approved MISSISSIPPI's Environmental
Compliance Overview Plan (ECO Plan). The ECO Plan establishes procedures to
facilitate the Mississippi PSC's overview of MISSISSIPPI's environmental
strategy and provides for recovery of costs (including costs of capital
associated with environmental projects approved by the Mississippi PSC). Under
the ECO Plan, any increase in the annual revenue requirement is limited to 2
percent of retail revenues. However, the ECO Plan also provides for carryover of
any amount over the 2 percent limit into the next year's revenue requirement.
MISSISSIPPI conducts studies, when possible, to determine the extent of any
required environmental remediation. Should such remediation be determined to be
probable, reasonable estimates of costs to clean up such sites are developed and
recognized in the financial statements. MISSISSIPPI recovers such costs under
the ECO Plan as they are incurred, as provided for in MISSISSIPPI's 1995 ECO
Plan order. MISSISSIPPI filed its 2002 ECO Plan in January 2002, which, if
approved as filed, will result in a slight increase in customer prices.

Employee Relations

The SOUTHERN system had a total of 26,122 employees on its payroll at December
31, 2001.

 --------------------------------------------------------------
                                             Employees
                                                 at
                                         December 31, 2001
                                      -------------------------
 ALABAMA                                          6,706
 GEORGIA                                          9,048
 GULF                                             1,309
 MISSISSIPPI                                      1,316
 SAVANNAH                                           550
 SCS                                              3,569
 Southern Nuclear                                 3,045
 Other                                              579
 --------------------------------------------------------------
 Total                                           26,122
 ==============================================================

     The operating companies have separate agreements with local unions of the
IBEW generally covering wages, working conditions and procedures for handling
grievances and arbitration. These agreements apply with certain exceptions to
operating, maintenance and construction employees.

     ALABAMA has agreements with the IBEW on a three-year contract extending to
August 14, 2005. Upon notice given at least 60 days prior to that date,
negotiations may be initiated with respect to agreement terms to be effective
after such date.

     GEORGIA has an agreement with the IBEW covering wages and working
conditions, which is in effect through June 30, 2002.

     GULF has an agreement with the IBEW on a three-year contract extending to
August 15, 2005.

    MISSISSIPPI has an agreement with the IBEW on a four-year contract extending
to August 16, 2002.

     SAVANNAH has four-year labor agreements with the IBEW and the Office and
Professional Employees International Union that expire April 15, 2003 and
December 1, 2003, respectively.

     Southern Nuclear has agreements with the IBEW on a five-year contract
extending to August 15, 2006 for Plant Farley and a three-year contract
extending to June 30, 2002 for Plants Hatch and Vogtle. Upon notice given at

                                      I-18
<PAGE>

least 60 days prior to these dates, negotiations may be initiated with respect
to agreement terms to be effective after such dates.

    Southern Nuclear is currently in negotiations with the Security, Police and
Fire Professionals of America (formerly the United Plant Guard Workers of
America) at Plant Hatch. The prior contract with the United Plant Guard Workers
of America which extended to September 30, 2001 was not terminated, so the terms
of the existing agreement have continued as negotiations of the new agreement
continues. The parties will have the opportunity to terminate the agreement 60
days prior to October 1, 2002 if no agreement is reached prior to that time.

    The agreements also subject the terms of the pension plans for the companies
discussed above to collective bargaining with the unions at five-year intervals.

                                      I-19


<PAGE>


Item 2.  PROPERTIES

Electric Properties - The Electric Utilities

The operating companies, Southern Power and SEGCO, at December 31, 2001, owned
and/or operated 34 hydroelectric generating stations, 34 fossil fuel generating
stations, three nuclear generating stations and five combined cycle/cogeneration
stations. The amounts of capacity for each company are shown in the table below.

 ------------------------- -------------------------------------
                                                  Nameplate
 Generating Station        Location              Capacity (1)
 ------------------------- ------------------- -----------------
                                                 (Kilowatts)
 Fossil Steam
 Gadsden                   Gadsden, AL              120,000
 Gorgas                    Jasper, AL             1,221,250
 Barry                     Mobile, AL             1,525,000
 Greene County             Demopolis, AL            300,000 (2)
 Gaston Unit 5             Wilsonville, AL          880,000
 Miller                    Birmingham, AL         2,532,288 (3)
                                                  ---------
 ALABAMA Total                                    6,578,538
                                                  ---------

 Arkwright                 Macon, GA                160,000
 Atkinson                  Atlanta, GA              180,000
 Bowen                     Cartersville, GA       3,160,000
 Branch                    Milledgeville, GA      1,539,700
 Hammond                   Rome, GA                 800,000
 McDonough                 Atlanta, GA              490,000
 McManus                   Brunswick, GA            115,000
 Mitchell                  Albany, GA               170,000
 Scherer                   Macon, GA                750,924 (4)
 Wansley                   Carrollton, GA           925,550 (5)
 Yates                     Newnan, GA             1,250,000
                                                  ---------
 GEORGIA Total                                    9,541,174
                                                  ---------

 Crist                     Pensacola, FL          1,045,000
 Lansing Smith             Panama City, FL          305,000
 Scholz                    Chattahoochee, FL         80,000
 Daniel                    Pascagoula, MS           500,000 (6)
 Scherer Unit 3            Macon, GA                204,500 (4)
                                                  ---------
 GULF Total                                       2,134,500
                                                  ---------

 Eaton                     Hattiesburg, MS           67,500
 Sweatt                    Meridian, MS              80,000
 Watson                    Gulfport, MS           1,012,000
 Daniel                    Pascagoula, MS           500,000 (6)
 Greene County             Demopolis, AL            200,000 (2)
                                                -----------
 MISSISSIPPI Total                                1,859,500
                                                -----------
 ---------------------------------------------- ----------------


 ------------------------- -----------------------------------------
                                                      Nameplate
 Generating Station     Location                       Capacity
 ---------------------- ------------------------- ------------------
                                                     (Kilowatts)
 McIntosh               Effingham County, GA           163,117
 Kraft                  Port Wentworth, GA             281,136
 Riverside              Savannah, GA                   102,278
                                                   -----------
 SAVANNAH Total                                        546,531
                                                   -----------

 Gaston Units 1-4       Wilsonville, AL
 SEGCO Total                                         1,000,000 (7)
                                                   -----------
 Total Fossil Steam                                 21,660,243
                                                   -----------

 Nuclear Steam
 Farley                 Dothan, AL
 ALABAMA Total                                       1,720,000
                                                   -----------
 Hatch                  Baxley, GA                     899,612 (8)
 Vogtle                 Augusta, GA                  1,060,240 (9)
                                                   -----------
 GEORGIA Total                                       1,959,852
                                                   -----------
 Total Nuclear Steam                                 3,679,852
                                                   -----------

 Combustion Turbines
 Greene County          Demopolis, AL
 ALABAMA Total                                         720,000
                                                   -----------

 Arkwright              Macon, GA                       30,580
 Atkinson               Atlanta, GA                     78,720
 Bowen                  Cartersville, GA                39,400
 Intercession City      Intercession City, FL           47,333 (10)
 McDonough              Atlanta, GA                     78,800
 McIntosh
   Units 1,2,3,4,7,8    Effingham County, GA           480,000
 McManus                Brunswick, GA                  481,700
 Mitchell               Albany, GA                     118,200
 Robins                 Warner Robins, GA              160,000
 Wilson                 Augusta, GA                    354,100
 Wansley                Carrollton, GA                  26,322 (5)
                                                   -----------
 GEORGIA Total                                       1,895,155
                                                   -----------

 Lansing Smith
   Unit A               Panama City, FL                 39,400
 Pea Ridge
   Units 1-3            Pea Ridge, FL                   14,250
                                                        ------
 GULF Total                                             53,650
                                                        ------

 Chevron Cogenerating
   Station              Pascagoula, MS                 147,292 (11)
 Sweatt                 Meridian, MS                    39,400
 Watson                 Gulfport, MS                    39,360
                                                     ---------
 MISSISSIPPI Total                                     226,052
                                                     ---------



 ------------------------------------------------- -----------------

                                      I-20
<PAGE>


 --------------------------- -------------------- -----------------
                                                    Nameplate
 Generating Station          Location                 Capacity
 --------------------------- -------------------- -----------------
                                                    (Kilowatts)
 Boulevard                   Savannah, GA              59,100
 Kraft                       Port Wentworth,
                               GA                      22,000
 McIntosh
 Units 5&6                   Effingham
                               County, GA             160,000
                                                      -------
 SAVANNAH Total                                       241,100
                                                      -------


 Dahlberg                                             800,000
                                                      -------
 Southern Power Total                                 800,000
                                                      -------

 Gaston (SEGCO)              Wilsonville, AL           19,680 (7)
                                                  -----------
 Total Combustion Turbines                          3,955,637
                                                  -----------

 Cogeneration
 Washington County           Washington
                               County, AL             123,428
 GE Plastics Project         Burkeville, AL           104,800
 Theodore                    Theodore, AL             236,418
                                                  -----------
 Total Cogeneration                                   464,646
                                                  -----------

 Combined Cycle
 Barry                       Mobile, AL
 ALABAMA Total                                      1,070,424
                                                    ---------

 Daniel
    (Leased)                 Pascagoula, MS
 Mississippi Total                                  1,070,424
                                                    ---------
 Total Combined Cycle                               2,140,848
                                                    ---------

 Hydroelectric Facilities

 Weiss                       Leesburg, AL              87,750
 Henry                       Ohatchee, AL              72,900
 Logan Martin                Vincent, AL              128,250
 Lay                         Clanton, AL              177,000
 Mitchell                    Verbena, AL              170,000
 Jordan                      Wetumpka, AL             100,000
 Bouldin                     Wetumpka, AL             225,000
 Harris                      Wedowee, AL              135,000
 Martin                      Dadeville, AL            154,200
 Yates                       Tallassee, AL             32,000
 Thurlow                     Tallassee, AL             60,000
 Lewis Smith                 Jasper, AL               157,500
 Bankhead                    Holt, AL                  54,000
 Holt                        Holt, AL                  46,000
                                                   ----------
 ALABAMA Total                                      1,599,600
                                                   ----------

 --------------------------- -------------------- -----------------



 --------------------------- -------------------- -----------------
                                                    Nameplate
 Generating Station          Location                 Capacity
 --------------------------- -------------------- -----------------


 Barnett Shoals
   (Leased)                  Athens, GA                 2,800
 Bartletts Ferry             Columbus, GA             173,000
 Goat Rock                   Columbus, GA              26,000
 Lloyd Shoals                Jackson, GA               14,400
 Morgan Falls                Atlanta, GA               16,800
 North Highlands             Columbus, GA              29,600
 Oliver Dam                  Columbus, GA              60,000
 Rocky Mountain              Rome, GA                 215,256 (12)
 Sinclair Dam                Milledgeville, GA         45,000
 Tallulah Falls              Clayton, GA               72,000
 Terrora                     Clayton, GA               16,000
 Tugalo                      Clayton, GA               45,000
 Wallace Dam                 Eatonton, GA             321,300
 Yonah                       Toccoa, GA                22,500
 6 Other Plants                                        18,080
                                                  -----------
 GEORGIA Total                                      1,077,736
                                                  -----------
 Total Hydroelectric Facilities                     2,677,336
                                                  -----------
 Total Generating Capacity                         34,578,562
                                                  ===========

 ------------------------------------------------ -----------------

Notes:
    (1)  For additional information regarding facilities jointly-owned with
         non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned
         Facilities" herein.
    (2)  Owned by ALABAMA and MISSISSIPPI as
         tenants in common in the proportions of 60% and 40%, respectively.
    (3)  Excludes the capacity owned by AEC.
    (4)  Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3.
         Capacity shown for GULF is 25% of Unit 3.
    (5)  Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
    (6)  Represents 50% of the plant which is owned as tenants in common by
         GULF and MISSISSIPPI.
    (7)  SEGCO is jointly-owned by ALABAMA and GEORGIA.  (See Item 1 - BUSINESS
         herein.)
    (8)  Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
    (9)  Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
   (10)  Capacity shown represents 33-1/3% of total plant capacity. GEORGIA owns
         a 1/3 interest in the unit with 100% use of the unit from June through
         September. FPC operates the unit.
   (11)  Generation is dedicated to a single industrial customer.
   (12)  Capacity shown is GEORGIA's portion (25.4%) of total plant capacity.
         OPC operates the plant.
                                      I-21

<PAGE>


     Except as discussed below under "Titles to Property," the principal plants
and other important units of the operating companies, Southern Power and SEGCO
are owned in fee by the respective companies. It is the opinion of management of
each such company that its operating properties are adequately maintained and
are substantially in good operating condition.

     MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which
is leased to Entergy Gulf States. The line, completed in 1984, extends from
Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use
fee over a forty-year period covering all expenses and the amortization of the
original $57 million cost of the line. At December 31, 2001, the unamortized
portion of this cost was approximately $33.3 million.

     The all-time maximum demand on the operating companies and SEGCO was
31,359,000 kilowatts and occurred in August 2000. This amount excludes demand
served by capacity retained by MEAG and Dalton and excludes demand associated
with power purchased from OPC and SEPA by its preference customers. The reserve
margin for the operating companies and SEGCO at that time was 8.1%. For
additional information on peak demands, reference is made to Item 6 - SELECTED
FINANCIAL DATA herein.

    ALABAMA and GEORGIA will incur significant costs in decommissioning their
nuclear units at the end of their useful lives. (See Item 1 - BUSINESS -
"Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.)

Jointly-Owned Facilities

ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in
certain generating plants and other related facilities to or from non-affiliated
parties. The percentages of ownership resulting from these transactions are as
follows:

<TABLE>
<CAPTION>


                           Total Percentage Ownership
                                                 ---------------- -------- ------------ -------- --------- ------------ --------
                                 Capacity        ALABAMA          AEC      GEORGIA      OPC      MEAG      DALTON        FPC
                               --------------    ---------------- -------- ------------ -------- --------- ------------ --------
                               (Megawatts)
<S>                                <C>               <C>           <C>         <C>      <C>        <C>       <C>        <C>

    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
 ----------------------------- -------------- -- ---------------- -------- ------------ -------- --------- ------------ --------

</TABLE>

     ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain and Intercession
City, as described below) as agent for the joint owners.

     In addition, GEORGIA has commitments regarding a portion of a 5 percent
interest in Plant Vogtle owned by MEAG that are in effect until the later of
retirement of the plant or the latest stated maturity date of MEAG's bonds
issued to finance such ownership interest. The payments for capacity are
required whether any capacity is available. The energy cost is a function of
each unit's variable operating costs. Except for the portion of the capacity
payments related to the 1987 and 1990 write-offs of Plant Vogtle costs, the
cost of such capacity and energy is included in purchased power from
non-affiliates in GEORGIA's Statements of Income in Item 8 herein.

                                      I-22
<PAGE>


    Additional jointly-owned facilities also include Southern Power's 65%
undivided interest in Stanton Unit A and related facilities jointly owned with
the Orlando Utilities Commission, the Kissimmee Utility Authority and the
Florida Municipal Power Agency. Currently under construction near Orlando,
Florida, this project will be a 610 megawatt combined cycle unit and is
scheduled for commerical operation in October 2003.

Titles to Property

The operating companies', Southern Power's and SEGCO's interests in the
principal plants (other than certain pollution control facilities, one small
hydroelectric generating station leased by GEORGIA, MISSISSIPPI's combined cycle
units at Plant Daniel and the land on which five combustion turbine generators
of MISSISSIPPI are located, which is held by easement) and other important units
of the respective companies are owned in fee by such companies, subject only to
the liens of applicable mortgage indentures of ALABAMA, GULF, MISSISSIPPI and
SAVANNAH and to excepted encumbrances as defined therein. The operating
companies own the fee interests in certain of their principal plants as tenants
in common. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.)
Properties such as electric transmission and distribution lines and steam
heating mains are constructed principally on rights-of-way which are maintained
under franchise or are held by easement only. A substantial portion of lands
submerged by reservoirs is held under flood right easements. In substantially
all of its coal reserve lands, SEGCO owns or will own the coal only, with
adequate rights for the mining and removal thereof.

                                      I-23

<PAGE>


Item 3. LEGAL PROCEEDINGS

(1)    United States of America v. ALABAMA
       (United States District Court for the Northern District of Alabama)

       On November 3, 1999, the EPA brought a civil action in the U.S. District
       Court in Georgia against ALABAMA. The complaint alleges violations of the
       New Source Review provisions of the Clean Air Act with respect to
       coal-fired generating facilities at ALABAMA's Plants Miller, Barry and
       Gorgas. The civil action requests penalties and injunctive relief,
       including an order requiring the installation of the best available
       control technology at the affected units. The Clean Air Act authorizes
       civil penalties of up to $27,500 per day, per violation at each
       generating unit. Prior to January 30, 1997, the penalty was $25,000 per
       day. The EPA concurrently issued a notice of violation relating to these
       specific facilities, as well as Plants Greene County and Gaston. On
       August 1, 2000, the U.S. District Court granted ALABAMA's motion to
       dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA
       re-filed its claims against ALABAMA in federal district court in
       Birmingham, Alabama. ALABAMA's case has been stayed since the spring of
       2001, pending a ruling by the U.S. Court of Appeals for the Eleventh
       Circuit in the appeal of a very similar New Source Review enforcement
       action against the TVA. The TVA case involves many of the same legal
       issues raised by the actions against ALABAMA. Because the outcome of the
       TVA case could have a significant adverse impact on ALABAMA, ALABAMA is
       party to that case as well.

       ALABAMA believes that it complied with applicable laws and the EPA's
       regulations and interpretations in effect at the time the work in
       question took place. An adverse outcome of this matter could require
       substantial capital expenditures that cannot be determined at this time
       and possibly require payment of substantial penalties.

(2)    United States of America v. GEORGIA and SAVANNAH
       (United States District Court for the Northern District of Georgia)

       On November 3, 1999, the EPA brought a civil action in the U.S. District
       Court in Georgia against GEORGIA. The complaint alleges violation of the
       New Source Review provisions of the Clean Air Act with respect to
       coal-fired generating facilities at GEORGIA's Plants Bowen and Scherer.
       The civil action requests penalties and injunctive relief, including an
       order requiring the installation of the best available control technology
       at the affected units. The Clean Air Act authorizes civil penalties of up
       to $27,500 per day, per violation at each generating unit. Prior to
       January 30, 1997, the penalty was $25,000 per day. On March 27, 2001, the
       U.S. District Court granted the EPA's motion to amend its complaint to
       add the alleged violations at SAVANNAH's Plant Kraft and to add SAVANNAH
       as a defendant. The EPA concurrently issued a notice of violation
       relating to these two GEORGIA plants and SAVANNAH's Plant Kraft.

       The case has been stayed since the spring of 2001, pending a ruling by
       the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a
       very similar New Source Review enforcement action against the TVA. The
       TVA case involves many of the same legal issues raised by the actions
       against GEORGIA and SAVANNAH. Because the outcome of the TVA case could
       have a significant adverse impact on GEORGIA and SAVANNAH, both GEORGIA
       and SAVANNAH are party to that case as well.

       GEORGIA and SAVANNAH believe that they complied with applicable laws and
       the EPA's regulations and interpretations in effect at the time the work
       in question took place. An adverse outcome of this matter could require
       substantial capital expenditures that cannot be determined at this time
       and possibly require payment of substantial penalties.

                                      I-24
<PAGE>


Item 3.  LEGAL PROCEEDINGS (continued)

(3)    Cooper et al. v. GEORGIA, SOUTHERN, SCS and Energy Solutions
       (Superior Court of Fulton County, Georgia)

       On July 28, 2000, a lawsuit alleging race discrimination was filed by
       three GEORGIA employees against GEORGIA, SOUTHERN, and SCS in the
       Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit
       was removed to the United States District Court for the Northern District
       of Georgia. The lawsuit also raised claims on behalf of a purported
       class. The plaintiffs seek compensatory and punitive damages in an
       unspecified amount, as well as injunctive relief. On August 14, 2000, the
       lawsuit was amended to add four more plaintiffs. Also, an additional
       subsidiary of SOUTHERN, Energy Solutions (now Southern Management
       Development), was named a defendant.

       On October 11, 2001, the district court denied the plaintiffs' motion for
       class certification. The plaintiffs filed a motion to reconsider the
       order denying class certification, and the court denied the plaintiffs'
       motion to reconsider. On December 28, 2001, the plaintiffs filed a
       petition in the United States Court of Appeals for the Eleventh Circuit
       seeking permission to file an appeal of the October 11 decision. On March
       15, 2002, the Eleventh Circuit denied the plaintiffs' petition; thus, the
       plaintiffs may not appeal the October 11 decision until the seven
       individual cases are resolved in the district court. Discovery on the
       seven named plaintiffs' individual claims that remain in the case is
       ongoing. The final outcome of the case cannot now be determined.

(4)    GEORGIA has been designated as a potentially responsible party at sites
       governed by the Georgia Hazardous Site Response Act and/or by the federal
       Comprehensive Environmental Response, Compensation and Liability Act.

       In addition, in 1995 the EPA designated GEORGIA and four other unrelated
       entities as potentially responsible parties at a site in Brunswick,
       Georgia that is listed on the federal National Priorities List. GEORGIA
       has contributed to the removal and remedial investigation and feasibility
       study costs for the site. Additional claims for recovery of natural
       resource damages at the site are anticipated.

       The final outcome of these matters cannot now be determined.

       Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
       statements in Item 8 herein under the captions "Georgia Power Potentially
       Responsible Party Status" and "Other Environmental Contingencies,"
       respectively.

(5)    In re: Mobile Energy Services Company, LLC; In re: Mobile Energy
       Services Holdings, Inc.
       (U.S. Bankruptcy Court for the Southern District of Alabama).

       On August 4, 2000, MESH filed a proposed plan of reorganization with the
       U.S. Bankruptcy Court. The proposed plan of reorganization was most
       recently amended on October 15, 2001. SOUTHERN expects that approval of a
       plan of reorganization would result in either a termination of SOUTHERN's
       ownership interest in MESH or the exchange of all assets of MESH for the
       cancellation of securities held by the bondholders, but would not affect
       SOUTHERN's continuing guarantee obligations. The final outcome of this
       matter cannot now be determined.

       Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
       herein under the caption "Mobile Energy Services' Petition for
       Bankruptcy."

                                      I-25
<PAGE>


Item 3. LEGAL PROCEEDINGS (continued)

(6)    Gordon v. SOUTHERN et al.
       (United States District Court for the Southern District of California)
                            and
(7)    Pier 23 Restaurant v. SOUTHERN et al.
       (United States District Court for the Northern District of California)

       Prior to the spin off of Mirant, SOUTHERN was named as a defendant in two
       lawsuits filed in the superior courts of California alleging that certain
       owners of electric generation facilities in California, including
       SOUTHERN, engaged in various unlawful and anticompetitive acts that
       served to manipulate wholesale power markets and inflate wholesale
       electricity prices in California. One lawsuit naming SOUTHERN, Mirant and
       other generators as defendants alleged that, as a result of the
       defendants' conduct, customers paid approximately $4 billion more for
       electricity that they otherwise would have and sought an award of treble
       damages, as well as other injunctive and equitable relief. The other suit
       likewise sought treble damages and equitable relief. The allegations in
       the two lawsuits in which SOUTHERN was named seemed to be directed to
       activities of subsidiaries of Mirant. On September 28 and November 6,
       2001, the plaintiffs voluntarily dismissed SOUTHERN without prejudice
       from the two lawsuits in which it had been named as a defendant. Prior to
       being dismissed, SOUTHERN had notified Mirant of its claim for
       indemnification for costs associated with the lawsuits under the terms of
       the master separation agreement that governs the spin off of Mirant.
       Mirant had undertaken the defense of the lawsuits. Plaintiffs would not
       be barred by their own dismissal from naming SOUTHERN in some future
       lawsuit, but management believes that the likelihood of SOUTHERN having
       to pay damages in any such lawsuit is remote.


     See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's
financial statements in Item 8 herein for a description of certain other
administrative and legal proceedings discussed therein.

     Additionally, each of the operating companies, SCS, Southern Nuclear,
Southern Power, Energy Solutions and Southern LINC are, in the normal course of
business, engaged in litigation or administrative proceedings that include, but
are not limited to, acquisition of property, injuries and damages claims, and
complaints by present and former employees.


                                      I-26

<PAGE>


Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

           ALABAMA

           ALABAMA held a special meeting of shareholders on November 21, 2001
           for the purpose of amending its charter to effect certain changes in
           the Auction Procedures for ALABAMA's 1988 Auction Series Class A
           Preferred Stock and 1993 Auction Series Class A Preferred Stock. The
           amendment was passed and the vote tabulation was as follows:
                                                     Votes
                             ------------------------------------------------
                                  For               Against         Abstain
                                  ---               -------         -------

           Common Stock        6,000,000               0                 0
           Preferred Stock       377,000               0                 0
                               ----------              -                 -
                Total          6,377,000               0                 0
                               =========               =                 =



                                      I-27

<PAGE>


EXECUTIVE OFFICERS OF SOUTHERN

(Identification of executive officers of SOUTHERN is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.

H. Allen Franklin
Chairman, President, Chief Executive Officer and Director
Age 57
Elected Director in 1988 and Chief Executive Officer effective March 1, 2001.
Previously served as President and Chief Operating Officer of SOUTHERN from June
1999 to March 2001; and as President and Chief Executive Officer of GEORGIA from
January 1994 to June 1999.

Dwight H. Evans
Executive Vice President
Age 53
Elected in 2001. Previously served as President and Chief Executive Officer of
MISSISSIPPI from March 1995 to May 2001.

David M. Ratcliffe
Executive Vice President
Age 53
Elected in 1999. He also has served as President and Chief Executive Officer of
GEORGIA since June 1999. Previously served as Executive Vice President,
Treasurer and Chief Financial Officer of GEORGIA from March 1998 to June 1999;
and as Senior Vice President of SOUTHERN from March 1995 to March 1998.

Leonard J. Haynes
Executive Vice President and Chief Marketing Officer
Age 51
Elected in 2001. Previously served as Senior Vice President of GEORGIA from
October 1998 to May 2001; and Vice President of GEORGIA from October 1992 to
October 1998.

G. Edison Holland, Jr.
Executive Vice President
Age 49
Elected in 2001. Previously served as President and Chief Executive Officer of
SAVANNAH from 1997 until 2001.

Gale E. Klappa
Executive Vice President, Chief Financial Officer and Treasurer
Age 51
Elected in 2001. Previously served as Financial Vice President, Chief Financial
Officer and Treasurer form March 2001 to May 2001; Senior Vice President and
Chief Strategic Officer of SOUTHERN from October 1999 to March 2001; President
of Mirant's North America Group and Senior Vice President of Mirant from
December 1998 to October 1999; and as President and Chief Executive Officer of
Western Power Distribution, a subsidiary of Mirant located in Bristol, England,
from September 1995 to December 1998.

Charles D. McCrary
Executive Vice President
Age 50
Elected in 1998; serves as President and Chief Executive Officer of ALABAMA.
Previously served as President and Chief Operating Officer of ALABAMA from May
2001 to October 2001; Vice President of SOUTHERN from February 1998 to April
2001; and as Executive Vice President of ALABAMA from 1994 through February
1998.

W. Paul Bowers
Age 44
Executive Vice President of SCS and President and Chief Executive Officer of
Southern Power since May 2001. Previously served as Senior Vice President of SCS
and Chief Marketing Officer of SOUTHERN from March 2000 to May 2001; President
and Chief Executive Officer of Western Power Distribution, a subsidiary of
Mirant located in Bristol, England, from December 1998 to 2000; and Senior Vice
President of Retail Marketing for GEORGIA from 1995 to 1998.

W. G. Hairston, III
Age 57
President and Chief Executive Officer of Southern Nuclear since 1993.

     The officers of SOUTHERN were elected for a term running from the first
meeting of the directors following the last annual meeting (May 23, 2001) for
one year until the first board meeting after the next annual meeting or until
their successors are elected and have qualified.

                                      I-28
<PAGE>


EXECUTIVE OFFICERS OF ALABAMA

(Identification of executive officers of ALABAMA is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.

Elmer B. Harris
Chairman and Director*
Age 62
Elected in 1989. Served as President and Chief Executive Officer from 1989 to
2001. Elected Executive Vice President of SOUTHERN in 1991. Served as a Director
of SOUTHERN since 1989.

Charles D. McCrary
President, Chief Executive Officer and Director
Age 50
Elected in 2001. Served as President and Chief Operating Officer of ALABAMA from
April 2001 to October 2001 and Vice President of SOUTHERN from February 1998 to
April 2001. Previously served as Executive Vice President of External Affairs at
ALABAMA from April 1994 through February 1998.

William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 58
Elected in 1991. Served as Treasurer since 1998 in addition to Executive Vice
President and Chief Financial Officer since 1991.

C. Alan Martin
Executive Vice President
Age 53
Elected in 1999. Served as Executive Vice President of External Affairs since
January 2000. Previously served as Executive Vice President and Chief Marketing
Officer for SOUTHERN from 1998 to 1999; and Vice President of Human Resources
for SOUTHERN from May 1995 to March 1998.

Steve R. Spencer
Executive Vice President
Age 46
Elected in 2001. Served as Senior Vice President of External Affairs from July
2000 to April 2001. Previously served as Vice President of SOUTHERN's external
affairs organization from 1998 to 2001.

Jerry L. Stewart
Senior Vice President
Age 52
Elected in 1999. Served as Senior Vice President of Fossil and Hydro Generation
since 1999. Previously served as Vice President of SCS from 1992 to 1999.

     The officers of ALABAMA were elected for a term running from the last
annual meeting of the directors (April 27, 2001) for one year until the next
annual meeting or until their successors are elected and have qualified, except
for Mr. McCrary who was elected Chief Executive Officer on October 25, 2001.

*Retired effective January 11, 2002.

                                      I-29
<PAGE>


EXECUTIVE OFFICERS OF GEORGIA

(Identification of executive officers of GEORGIA is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.

David M. Ratcliffe
President, Chief Executive Officer and Director
Age 53
Elected as an Executive Officer in 1998 and as Director in 1999. Served as
President and Chief Executive Officer since June 1999. Previously served as
Executive Vice President, Treasurer and Chief Financial Officer of GEORGIA from
1998 to 1999; and as Senior Vice President of SOUTHERN from March 1995 to March
1998.

William C. Archer, III
Executive Vice President
Age 53
Elected in 1995.  Served as Executive Vice President of External Affairs since
1995.

Thomas A. Fanning
Executive Vice President, Treasurer and
Chief Financial Officer
Age 44
Elected in 1999. Previously served as Senior Vice President of SCS and Chief
Information Officer for SOUTHERN from March 1995 to June 1999.

Judy M. Anderson
Senior Vice President
Age 53
Elected in 2001. Served as Senior Vice President of Charitable Giving since
2001. Previously served as Vice President and Corporate Secretary of GEORGIA
from 1989 to 2001.

Ronnie L. Bates
Senior Vice President
Age 47
Elected in 2001. Served as Senior Vice President, Marketing since 2001.
Previously served as Vice President, Transmission from 2000 to 2001; and as
General Manager, Transmission and Construction from 1995 to 2000.

Mickey A. Brown
Senior Vice President
Age 54
Elected in 2001. Served as Senior Vice President of Distribution since 2001.
Previously served as Vice President, Distribution from 2000 to 2001; and as Vice
President, Northern Region from 1993 to 2000.

James K. Davis
Senior Vice President
Age 61
Elected in 1993. Served as Senior Vice President of Corporate Relations since
1993, with Employee Relations being added to his responsibilities in 2000.

Fred D. Williams
Senior Vice President
Age 57
Elected in 1992. Served as Senior Vice President of Resource Policy and Planning
since 1997. Previously served as Senior Vice President of Wholesale Energy from
1995 to 1997.

Leslie R. Sibert
Vice President
Age 39
Elected in 2001. Served as Vice President, Transmission since 2001. Previously
served as Decatur Region Manager from 1999 to 2001; and as Assistant to Senior
Vice President, Southern Wholesale Energy from 1996 to 1999.

Christopher C. Womack
Senior Vice President
Age 43
Elected in 2001. Served as Senior Vice President of Fossil and Hydro since 2001.
Previously served as Vice President and Chief People Officer of SOUTHERN from
1998 to 2001; and as Senior Vice President of Public Relations and Corporate
Services at ALABAMA from 1995 to 1998.

    The officers of GEORGIA were elected for a term running from the last annual
meeting of the directors (May 16, 2001) for one year until the next annual
meeting or until their successors are elected and have qualified, except for Ms.
Anderson, whose election was effective June 1, 2001; Mr. Bates, whose election
was effective October 8, 2001; Ms. Sibert, whose election was effective November
14, 2001; and Mr. Womack, whose election was effective December 17, 2001.

                                      I-30
<PAGE>


EXECUTIVE OFFICERS OF GULF

(Identification of executive officers of GULF is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.

Travis J. Bowden
President, Chief Executive Officer and Director
Age 63
Elected in 1994.  Served as President and Chief Executive Officer since 1994.

Francis M. Fisher, Jr.
Vice President
Age 53
Elected in 1989.  Served as Vice President of Power Delivery and Customer
Operations since 1996.

John E. Hodges, Jr.
Vice President
Age 58
Elected in 1989. Served as Vice President of Marketing and Employee/External
Affairs since 1996.

Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
Age 48
Elected in 2000. Served as Vice President, Chief Financial Officer and
Comptroller since 2001. Previously served as Comptroller and Chief Financial
Officer from 2000 to 2001 and Controller from 1992 to 2000.

Robert G. Moore
Vice President
Age 52
Elected in 1997. Served as Vice President of Power Generation and Transmission
of GULF and Vice President of Fossil Generation of SCS since 1997. Previously
served as Plant Manager of Plant Bowen at GEORGIA from March 1993 to August
1997.

Warren E. Tate
Vice President, Secretary/Treasurer and
Regional Chief Information Officer
Age 59
Elected in 2000. Served as Vice President since 2001, also serves as
Secretary/Treasurer and Regional Chief Information Officer since 1996.

    The officers of GULF were elected for a term running from the last annual
meeting of the directors (July 27, 2001) for one year until the next annual
meeting or until their successors are elected and have qualified.


                                      I-31
<PAGE>


EXECUTIVE OFFICERS OF MISSISSIPPI

(Identification of executive officers of MISSISSIPPI is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 2001.

Michael D. Garrett
President, Chief Executive Officer and Director
Age 52
Elected in 2001. Previously served as Executive Vice President - Customer
Service of ALABAMA from January 2000 to May 2001; Executive Vice President of
External Affairs of ALABAMA from March 1998 to January 2000; and Senior Vice
President of External Affairs of ALABAMA from February 1994 to March 1998.

H. E. Blakeslee
Vice President
Age 61
Elected in 1984.  Served as Vice President of Customer Services and Retail
Marketing since 1984.

Don E. Mason
Vice President
Age 60
Elected in 1983.  Served as Vice President of External Affairs and Corporate
Services since 1983.

Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer
Age 49
Elected in 1995.  Served as Vice President, Treasurer and Chief Financial
Officer since 2001.  Previously served as Vice President,
Secretary, Treasurer and Chief Financial Officer from 1995 to 2001.

Gene L. Ussery, Jr.
Vice President
Age 52
Elected in 2000. Served as Vice President of Power Generation and Delivery since
September 2000. Previously served as Northern Cluster Manager at GEORGIA for
Plants Hammond, Bowen and McDonough-Atkinson from July 2000 to September 2000.
He served as Manager of Plant Bowen at GEORGIA from 1997 to 2000; and Manager of
Plant McDonough at GEORGIA from 1996 to 1997.

     The officers of MISSISSIPPI were elected for a term running from the last
annual meeting of the directors (April 25, 2001) for one year until the next
annual meeting or until their successors are elected and have qualified.


                                      I-32
<PAGE>

                                               PART II

Item 5.    MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

      (a)  The common stock of SOUTHERN is listed and traded on the New York
           Stock Exchange. The stock is also traded on regional exchanges across
           the United States. High and low stock prices, per the New York Stock
           Exchange Composite Tape during each quarter for the past two years
           were as follows:

           ------------------------ ------------ -- --------------
                                       High              Low
                                    ------------    --------------

           2001
           First Quarter (Note)       $21.650         $16.152
           Second Quarter              23.880          20.890
           Third Quarter               26.000          22.050
           Fourth Quarter              25.980          22.300

           2000
           First Quarter             $25.875          $20.375
           Second Quarter             27.875           21.688
           Third Quarter              35.000           23.406
           Fourth Quarter             33.880           27.500
           ---------------------- -------------- -- --------------

           Note:   The common stock high and low prices have been adjusted to
                   give effect to the Mirant spin off. Reference is made to Note
                   11 to the financial statements for SOUTHERN in Item 8 herein
                   for additional information.

           There is no market for the other registrants' common stock, all of
           which is owned by SOUTHERN. On February 28, 2002, the closing price
           of SOUTHERN's common stock was $25.40.

      (b)  Number of SOUTHERN's common stockholders of record at December 31,
           2001:
                      150,242

           Each of the other registrants have one common stockholder, SOUTHERN.


      (c)  Dividends on each registrant's common stock are payable at the
           discretion of their respective board of directors.  The dividends on
           common stock declared by SOUTHERN and the operating companies to
           their stockholder(s) for the past two years were as follows: (in
           thousands)

           ------------------- --------- ------------- ----------
           Registrant          Quarter       2001          2000
           ------------------- --------- ------------- ----------

           SOUTHERN            First       $228,320     $220,557
                               Second       229,611      217,289
                               Third        231,192      217,289
                               Fourth       232,935      218,098

           ALABAMA             First        101,200      103,600
                               Second        97,600      105,200
                               Third         97,600      104,400
                               Fourth        97,500      103,900

           GEORGIA             First        134,500      136,500
                               Second       130,900      138,600
                               Third        130,900      137,600
                               Fourth       131,000      136,900

           GULF                First         13,500       14,600
                               Second        13,300       14,900
                               Third         13,300       14,800
                               Fourth        13,175       14,700

           MISSISSIPPI         First         12,800       13,600
                               Second        12,500       13,800
                               Third         12,500       13,700
                               Fourth        12,400       13,600

           SAVANNAH            First          5,500        6,100
                               Second         5,400        6,200
                               Third          5,400        6,000
                               Fourth         5,400        6,000
           ------------------- --------- ------------- ----------

    The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of
2000 and 2001. The dividend paid on SOUTHERN's common stock for the first
quarter of 2002 was 33.5(cent) per share.

    The amount of dividends on their common stock that may be paid by the
subsidiary registrants (except GEORGIA effective February 27, 2002) is
restricted in accordance with their respective first mortgage bond indenture.
The amounts of earnings retained in the

                                      II-1
<PAGE>


business and the amounts restricted against the payment of cash dividends on
common stock at December 31, 2001 were as follows:

 -------------------- ------------------ --- --------------
                          Retained            Restricted
                          Earnings              Amount
                      ------------------     --------------
                                  (in millions)
 ALABAMA                  $1,220                $   796
 GEORGIA                   1,871                  1,037
 GULF                        161                    127
 MISSISSIPPI                 186                    118
 SAVANNAH                    110                     68
 Consolidated              4,517                  2,145
 -------------------- ------------------ --- --------------

Item 6.    SELECTED FINANCIAL DATA

SOUTHERN.  Reference is made to information under the heading "Selected
Consolidated Financial and Operating Data," contained herein at pages II-43 and
II-44.

ALABAMA.  Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-78 and II-79.

GEORGIA.  Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-114 and II-115.

GULF.  Reference is made to information under the heading "Selected Financial
and Operating Data," contained herein at pages II-145 and II-146.

MISSISSIPPI.  Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-178 and II-179.

SAVANNAH.  Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-207 and II-208.

Item 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
         FINANCIAL CONDITION

SOUTHERN. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-8 through II-18.

ALABAMA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-48 through II-57.

GEORGIA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-83 through II-92.

GULF. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-119 through II-128.

MISSISSIPPI. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-150 through II-159.

SAVANNAH. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-183 through II-191.

Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Reference is made to information in SOUTHERN's "Management's Discussion and
Analysis - Market Price Risk" and to Note 1 to SOUTHERN's financial statements
under the heading "Financial Instruments" contained herein on pages II-14 and
II-29 through II-30, respectively.

Reference is also made to "Management's Discussion and Analysis - Exposure to
Market Risks" in Item 7 of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
contained herein at pages II-53, II-87 through II-88, II-124, II-155 and II-187,
respectively.
                                      II-2
<PAGE>
<TABLE>
<CAPTION>

Item 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2001 FINANCIAL STATEMENTS

                                                                                                                             Page
The Southern Company and Subsidiary Companies:

<S>                                                                                                                          <C>
Report of Independent Public Accountants................................................................................     II-7
Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999..................................     II-19
Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999..............................     II-20
Consolidated Balance Sheets at December 31, 2001 and 2000...............................................................     II-21
Consolidated Statements of Capitalization at December 31, 2001 and 2000.................................................     II-23
Consolidated Statements of Common Stockholders' Equity for the Years Ended
   December 31, 2001, 2000 and 1999.....................................................................................     II-25
Consolidated Statements of Comprehensive Income for the Years Ended
   December 31, 2001, 2000 and 1999.....................................................................................     II-25
Notes to Financial Statements...........................................................................................     II-26


ALABAMA:
Report of Independent Public Accountants  ..............................................................................     II-47
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999...............................................     II-58
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999...........................................     II-59
Balance Sheets at December 31, 2001 and 2000 ...........................................................................     II-60
Statements of Capitalization at December 31, 2001 and 2000 .............................................................     II-62
Statements of Common Stockholder's Equity for the Years Ended
    December 31, 2001, 2000 and 1999....................................................................................     II-64
Notes to Financial Statements...........................................................................................     II-65

GEORGIA:
Report of Independent Public Accountants................................................................................     II-82
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999...............................................     II-93
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999...........................................     II-94
Balance Sheets at December 31, 2001 and 2000............................................................................     II-95
Statements of Capitalization at December 31, 2001 and 2000 .............................................................     II-97
Statements of Comprehensive Income for the Years Ended
    December 31, 2001, 2000 and 1999....................................................................................     II-99
Statements of Common Stockholder's Equity for the Years Ended
    December 31, 2001, 2000 and 1999....................................................................................     II-99
Notes to Financial Statements...........................................................................................     II-100

GULF:
Report of Independent Public Accountants................................................................................     II-118
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999...............................................     II-129
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999...........................................     II-130
Balance Sheets at December 31, 2001 and 2000 ...........................................................................     II-131
Statements of Capitalization at December 31, 2001 and 2000 .............................................................     II-133
Statements of Common Stockholder's Equity for the Years Ended
    December 31, 2001, 2000 and 1999....................................................................................     II-134
Notes to Financial Statements...........................................................................................     II-135

                                      II-3
<PAGE>


                                                                                                                             Page
MISSISSIPPI:
Report of Independent Public Accountants................................................................................     II-149
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999...............................................     II-160
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999...........................................     II-161
Balance Sheets at December 31, 2001 and 2000 ...........................................................................     II-162
Statements of Capitalization at December 31, 2001 and 2000 .............................................................     II-164
Statements of Common Stockholder's Equity for the Years Ended
    December 31, 2001, 2000 and 1999....................................................................................     II-166
Notes to Financial Statements...........................................................................................     II-167

SAVANNAH:
Report of Independent Public Accountants................................................................................     II-182
Statements of Income for the Years Ended December 31, 2001, 2000 and 1999...............................................     II-192
Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999...........................................     II-193
Balance Sheets at December 31, 2001 and 2000 ...........................................................................     II-194
Statements of Capitalization at December 31, 2001 and 2000 .............................................................     II-196
Statements of Common Stockholder's Equity for the Years Ended
    December 31, 2001, 2000 and 1999....................................................................................     II-197
Notes to Financial Statements...........................................................................................     II-198
</TABLE>

Item 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
           ACCOUNTING AND FINANCIAL DISCLOSURE

None.

                                      II-4

<PAGE>

                                SOUTHERN COMPANY
                               FINANCIAL SECTION



                                      II-5
<PAGE>



MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 2001 Annual Report


The management of Southern Company has prepared -- and is responsible for -- the
consolidated financial statements and related information included in this
report. These statements were prepared in accordance with accounting principles
generally accepted in the United States and necessarily include amounts that are
based on the best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.

   The company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.

   The company's system of internal accounting controls is evaluated on an
ongoing basis by the company's internal audit staff. The company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.

   The audit committee of the board of directors, composed of four independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.

   Management believes that its policies and procedures provide reasonable
assurance that the company's operations are conducted according to a high
standard of business ethics.

   In management's opinion, the consolidated financial statements present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Southern Company and its subsidiary companies in conformity
with accounting principles generally accepted in the United States.



/s/H. Allen Franklin
H. Allen Franklin
Chairman, President, and Chief Executive Officer


/s/Gale E. Klappa
Gale E. Klappa
Executive Vice President, Chief Financial Officer,
and Treasurer
February 13, 2002



                                       II-6





<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Southern Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southern Company (a Delaware corporation) and
subsidiary companies as of December 31, 2001 and 2000, and the related
consolidated statements of income, comprehensive income, common stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

   We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

   In our opinion, the consolidated financial statements (pages II-19 through
II-42) referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 2001
and 2000, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States.

   As explained in Note 1 to the financial statements, effective January 1,
2001, Southern Company changed its method of accounting for derivative
instruments and hedging activities.





/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002



                                       II-7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 2001 Annual Report


RESULTS OF OPERATIONS
---------------------

OVERVIEW OF CONSOLIDATED EARNINGS AND DIVIDENDS

Earnings

Southern Company's basic earnings per share from continuing operations increased
6.6 percent in 2001. This increase was achieved by cost containment and lower
interest rates despite the mild temperatures and the economic downturn. Basic
earnings per share from continuing operations were $1.62 in 2001 compared with
$1.52 in 2000. Dilution -- which factors in additional shares related to stock
options -- decreased earnings per share by 1 cent in 2001 and had no impact in
2000.

   In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant Corporation -- formerly Southern Energy, Inc. -- and
intentions to spin off its remaining ownership of 272 million Mirant shares. On
April 2, 2001, the tax-free distribution of Mirant shares was completed at a
ratio of approximately 0.4 for every share of Southern Company common stock.

   As a result of the spin off, Southern Company's financial statements and
related information reflect Mirant as discontinued operations. Therefore, the
focus of Management's Discussion and Analysis is on Southern Company's
continuing operations. The following chart shows earnings from continuing and
discontinued operations:

                             Consolidated      Basic Earnings
                              Net Income          Per Share
                            --------------     -----------------
                             2001     2000      2001      2000
                            --------------     -----------------
                              (in millions)
Earnings from --
  Continuing
    operations             $1,120   $  994     $1.62     $1.52
  Discontinued
    operations                142      319      0.21      0.49
----------------------------------------------------------------
Total earnings             $1,262   $1,313     $1.83     $2.01
================================================================

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends
paid on common stock in 2001 and 2000 were $1.34 per share or 331/2 cents per
quarter. In January 2002, Southern Company declared a quarterly dividend of
331/2 cents per share. This is the 217th consecutive quarter that Southern
Company has paid a dividend equal to or higher than the previous quarter. Our
dividend payout ratio goal is 75 percent.

SOUTHERN COMPANY BUSINESS ACTIVITIES

Discussion of the results of continuing operations is focused on Southern
Company's primary business of electricity sales by the operating companies --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- and Southern Power. Southern Power is a new electric wholesale
generation subsidiary with market-based rates. The remaining portion of Southern
Company's other business activities include telecommunications, energy products
and services, leveraged leasing activities, and as the parent holding
company. The net impact of these other business activities on the consolidated
results of operations is not significant. See Note 12 to the financial
statements for additional information.

Electricity Business

Southern Company's electric utilities generate and sell electricity to retail
and wholesale customers in the Southeast. A condensed income statement for these
six companies is as follows:

                                           Increase (Decrease)
                              Amount         From Prior Year
                             -------      ----------------------
                                2001           2001       2000
-----------------------------------------------------------------
                                      (in millions)
Operating revenues            $9,906           $ 46       $735
-----------------------------------------------------------------
Fuel                           2,577             13        236
Purchased power                  718             41        268
Other operation
  and maintenance              2,489             19         40
Depreciation
  and amortization             1,144              9         89
Taxes other than
  income taxes                   533              1         11
-----------------------------------------------------------------
Total operating expenses       7,461             83        644
-----------------------------------------------------------------
Operating income               2,445            (37)        91
Other income, net                 15             51          2
-----------------------------------------------------------------
Earnings before
  interest and taxes           2,460             14         93
Interest expenses
  and other, net                 609            (25)        29
Income taxes                     702             (1)        28
-----------------------------------------------------------------
Net income                    $1,149           $ 40      $  36
=================================================================



                                      II-8
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Revenues

Operating revenues for the core business of selling electricity in 2001 and the
amount of change from the prior year are as follows:

                                           Increase (Decrease)
                              Amount         From Prior Year
                              ------      ----------------------
                                2001           2001       2000
----------------------------------------------------------------
                                      (in millions)
Retail --
  Base revenues               $5,921          $ (93)      $174
  Fuel cost recovery
    and other                  2,519            (67)       336
----------------------------------------------------------------
Total retail                   8,440           (160)       510
----------------------------------------------------------------
Sales for resale --
  Within service area            338            (39)        27
  Outside service area           836            236        127
----------------------------------------------------------------
Total sales for resale         1,174            197        154
Other operating
  revenues                       292              9         71
----------------------------------------------------------------
Operating revenues            $9,906          $  46       $735
================================================================
Percent change                                  0.5%       8.1%
----------------------------------------------------------------

   Base revenues declined by $93 million in 2001 because of mild temperatures
and the economic downturn. Total base revenues of $6.0 billion in 2000 increased
as a result of continued customer growth in the service area and the positive
impact of weather on energy sales.

   Electric rates -- for the operating companies -- include provisions to adjust
billings for fluctuations in fuel costs, the energy component of purchased power
costs, and certain other costs. Under these fuel cost recovery provisions, fuel
revenues generally equal fuel expenses -- including the fuel component of
purchased energy -- and do not affect net income. However, cash flow is affected
by the economic loss from untimely recovery of these receivables.

   Sales for resale revenues within the service area were $338 million in 2001,
down 10.2 percent from the prior year. This sharp decline resulted primarily
from the mild weather experienced in the Southeast during 2001, which
significantly reduced energy requirements from these customers. Sales for resale
within the service area for 2000 were up from the prior year as a result of
additional demand for electricity during the hot summer.

   Revenues from energy sales for resale outside the service area have increased
sharply the past two years with a 39 percent and 27 percent increase in 2001 and
2000, respectively. This growth was primarily driven by new contracts. As
Southern Company increases its competitive wholesale generation business, sales
for resale outside the service area should reflect steady increases over the
near term. Recent wholesale contracts have shorter contract periods, and many
are market priced compared with the traditional cost-based contracts entered
into in the 1980s. Those long-term cost-based contracts are principally unit
power sales to Florida utilities. Revenues from long-term unit power contracts
have both capacity and energy components. Capacity revenues reflect the
recovery of fixed costs and a return on investment under the contracts. Energy
is generally sold at variable cost. The capacity and energy components of the
unit power contracts were as follows:

                                    2001       2000       1999
--------------------------------------------------------------
                                          (in millions)
Capacity                            $170       $177       $174
Energy                               201        178        157
--------------------------------------------------------------
Total                               $371       $355       $331
==============================================================

   Capacity revenues in 2001 and 2000 varied slightly compared with the prior
year as a result of adjustments and true-ups related to contractual pricing. No
significant declines in the amount of capacity are scheduled until the
termination of the contracts in 2010.

Energy Sales

Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour sales for 2001 and the percent change by year were as
follows:

                        Amount            Percent Change
(billions of          --------      --------------------------
   kilowatt-hours)        2001      2001        2000      1999
------------------------------     ---------------------------
Residential               44.5      (3.6)%       6.5%     (0.2)%
Commercial                46.9       1.5         6.6       4.0
Industrial                52.9      (6.8)        1.0       1.6
Other                      1.0       0.7         2.7       1.6
Total retail             145.3      (3.2)        4.3       1.7
                         -----
Sales for resale --
  Within service area      9.4      (2.0)        1.5      (4.1)
  Outside service area    21.4      24.4        33.0      (0.4)
                        ------
Total                    176.1      (0.5)        6.4       1.2
==============================================================




                                       II-9
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


   Although the number of residential customers increased 43,000 in 2001, retail
energy sales registered a 3.2 percent decline. This is the first decrease since
1982. Reduced retail sales in 2001 were driven by extremely mild weather and the
sluggish economy, which severely impacted industrial sales. In 2000, the rate of
growth in total retail energy sales was very strong. Residential energy sales
reflected a substantial increase as a result of the hotter-than-normal summer
weather and the increase in customers served. Also in 2000, commercial sales
continued to reflect the strong economy in the Southeast. Energy sales to retail
customers are projected to increase at an average annual rate of 1.8 percent
during the period 2002 through 2012.

   Sales to customers outside the service area under long-term contracts for
unit power sales increased 2.7 percent in 2001 and increased 21 percent in 2000.
These changes in sales were influenced by weather -- discussed earlier -- and
fluctuations in prices for oil and natural gas. These are the primary fuel
sources for utilities with which the company has long-term contracts. However,
these fluctuations in energy sales under long-term contracts have minimal
effects on earnings because the energy is generally sold at variable cost.

Expenses

In 2001, operating expenses of $7.5 billion increased only $83 million compared
with the prior year. The moderate increase reflected flat energy sales and
tighter cost containment measures. The costs to produce electricity for the core
business in 2001 increased $96 million. However, non-production operation and
maintenance declined by $23 million.

   In 2000, operating expenses of $7.4 billion increased $644 million compared
with the prior year. The costs to produce electricity in 2000 increased by $498
million to meet higher energy requirements. Non-production operation and
maintenance expenses increased $46 million in 2000. Depreciation and
amortization expenses in 2000 increased $89 million, of which $50 million
resulted from additional accelerated amortization by Georgia Power.

   Fuel costs constitute the single largest expense for the six electric
utilities. The mix of fuel sources for generation of electricity is determined
primarily by system load, the unit cost of fuel consumed, and the availability
of hydro and nuclear generating units. The amount and sources of generation and
the average cost of fuel per net kilowatt-hour generated -- within the service
area -- were as follows:

                                    2001       2000       1999
---------------------------------------------------------------
Total generation
  (billions of kilowatt-hours)       174        174        165
Sources of generation
  (percent) --
    Coal                              72         78         78
    Nuclear                           16         16         17
    Oil and gas                        9          4          3
    Hydro                              3          2          2
Average cost of fuel per net
  kilowatt-hour generated
    (cents) --                      1.56       1.51       1.45
---------------------------------------------------------------

   In 2001, fuel and purchased power costs of $3.3 billion increased $54
million. Continued efforts to control energy costs combined with additional
efficient gas-fired generating units helped to hold the increase in fuel expense
to $13 million in 2001.

   Total fuel and purchased power costs increased $504 million in 2000 as a
result of 10.6 billion more kilowatt-hours being sold than in 1999. Demand was
met with some 2.5 billion additional kilowatt-hours being purchased and using
generation with higher unit fuel cost than in 1999.

   Total interest charges and other financing costs in 2001 decreased $25
million from amounts reported in the previous year. The decline reflected
substantially lower short-term interest rates that offset new financing costs.
Total interest charges and other financing costs in 2000 increased $29 million
reflecting some additional external financing for new generating units.

Effects of Inflation

The operating companies are subject to rate regulation and income tax laws that
are based on the recovery of historical costs. Therefore, inflation creates an
economic loss because the company is recovering its costs of investments in
dollars that have less purchasing power. While the inflation rate has been
relatively low in recent years, it continues to have an adverse effect on
Southern Company because of the large investment in utility plant with long
economic lives. Conventional accounting for historical cost does not recognize
this economic loss nor the partially offsetting gain that arises through


                                    II-10

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


financing facilities with fixed-money obligations such as long-term debt and
preferred securities. Any recognition of inflation by regulatory authorities is
reflected in the rate of return allowed.

Future Earnings Potential

General

The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of Southern
Company's future earnings depends on numerous factors. The two major factors are
the ability of the operating companies to achieve energy sales growth while
containing cost in a more competitive environment and the profitability of the
new competitive market-based wholesale generating facilities being added.

   Future earnings for the electricity business in the near term will depend
upon growth in energy sales, which is subject to a number of factors. These
factors include weather, competition, new short and long-term contracts with
neighboring utilities, energy conservation practiced by customers, the
elasticity of demand, and the rate of economic growth in the service area.

   The operating companies operate as vertically integrated companies providing
electricity to customers within the service area of the southeastern United
States. Prices for electricity provided to retail customers are set by state
public service commissions under cost-based regulatory principles. Retail rates
and earnings are reviewed and adjusted periodically within certain limitations
based on earned return on equity. See Note 3 to the financial statements for
additional information about these and other regulatory matters.

   In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, Southern Company recorded non-cash
income of approximately $124 million in 2001. Future pension income is dependent
on several factors including trust earnings and changes to the plan. For the
operating companies, pension income is a component of the regulated rates and
does not have a significant effect on net income. For more information, see Note
2 to the financial statements.

   Southern Company currently receives tax benefits related to investments in
alternative fuel partnerships and leveraged lease agreements for energy
generation, distribution, and transportation assets that contribute
significantly to the economic results for these projects. Changes in Internal
Revenue Service interpretations of existing regulations or challenges to the
company's positions could result in reduced availability or changes in the
timing of such tax benefits. The net income impact of these investments totaled
$52 million, $28 million, and $11 million in 2001, 2000, and 1999, respectively.
See Note 1 to the financial statements under "Leveraged Leases" and Note 6 for
additional information and related income taxes.

   Southern Company is involved in various matters being litigated. See Note 3
to the financial statements for information regarding material issues that could
possibly affect future earnings.

   Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters."

Industry Restructuring

The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are affected by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers.

   Although the Energy Act does not permit retail customer access, it has been a
major catalyst for recent restructuring and consolidations taking place within
the utility industry. Numerous federal and state initiatives are in varying
stages that promote wholesale and retail competition. Among other things, these
initiatives allow customers to choose their electricity provider. Some states
have approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While various restructuring and
competition initiatives have been discussed in Alabama, Florida, Georgia, and
Mississippi, none have been enacted. Enactment would require numerous issues to
be resolved, including significant ones relating to recovery of any stranded
investments, full cost recovery of energy produced, and other issues related to
the energy crisis that occurred in California. As a result of that crisis, many
states have either discontinued or delayed implementation of initiatives
involving retail deregulation.



                                      II-11


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


   Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if Southern Company's electric utilities do not remain low-cost
producers and provide quality service, then energy sales growth could be
limited, and this could significantly erode earnings.

   To adapt to a less regulated, more competitive environment, Southern Company
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets, or some combination thereof.
Furthermore, Southern Company may engage in new business ventures that arise
from competitive and regulatory changes in the utility industry. Pursuit of any
of the above strategies, or any combination thereof, may significantly affect
the business operations and financial condition of Southern Company.

   The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to allow holding companies to form exempt wholesale generators and foreign
utilities to sell power largely free from regulation under PUHCA. These entities
are able to own and operate power generating facilities and sell power to
affiliates -- under certain restrictions.

   Southern Company is working to maintain and expand its share of wholesale
energy sales in the Southeastern power markets. In January 2001, Southern
Company formed a new subsidiary -- Southern Power Company. This subsidiary
constructs, owns, and manages wholesale generating assets in the Southeast.
Southern Power will be the primary growth engine for Southern Company's
competitive wholesale market-based energy business. By the end of 2003, Southern
Power plans to have approximately 4,700 megawatts of generating capacity in
commercial operation. At December 31, 2001, 800 megawatts are in commercial
operation and some 3,900 megawatts of capacity are under construction.

   In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
Southern Company explained that it is developing a for-profit RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to
have a material impact on Southern Company's financial statements. The outcome
of this matter cannot now be determined.

Accounting Policies

Critical Policy

Southern Company's significant accounting policies are described in Note 1 to
the financial statements. The company's most critical accounting policy involves
rate regulation. The operating companies are subject to the provisions of FASB
Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In
the event that a portion of a company's operations is no longer subject to these
provisions, the company would be required to write off related regulatory assets
and liabilities that are not specifically recoverable and determine if any
other assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.

New Accounting Standards

Effective January 2001, Southern Company adopted FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended.
Statement No. 133 establishes accounting and reporting standards for derivative
instruments and for hedging activities. This statement requires that certain
derivative instruments be recorded in the balance sheet as either an asset or
liability measured at fair value and that changes in the fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. See Note 1 to the financial statements under "Financial Instruments" for
additional information. The impact on net income in 2001 was not material. An
additional interpretation of Statement No. 133 will result in a change --
effective April 1, 2002 -- in accounting for certain contracts related to fuel
supplies that contain quantity options. These contracts will be accounted for as
derivatives and marked to market. However, due to the existence of specific




                                     II-12
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


cost-based fuel recovery clauses for the operating companies, this change is not
expected to have a material impact on net income.

   In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. Southern Company adopted Statement No. 142 in January 2002 with no
material impact on the financial statements.

   Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. Southern Company has not yet quantified the impact of adopting
Statement No. 143 on its financial statements.

FINANCIAL CONDITION
------------------

Overview

Southern Company's financial condition continues to remain strong. In 2001, most
of the operating companies' earnings were at the high end of their respective
allowed range of return on equity. Also, earnings from new business activities
made a solid contribution. These factors drove consolidated net income from
continuing operations to a record $1.12 billion in 2001. The quarterly dividend
declared in January 2002 was 331/2 cents per share, or $1.34 on an annual basis.
Southern Company is committed to a goal of increasing the dividend over time
consistent with growth in earnings. Southern Company's target is to grow
earnings per share at an average annual rate of 5 percent or more. The dividend
payout ratio goal is 75 percent.

   Gross property additions to utility plant from continuing operations were
$2.6 billion in 2001. The majority of funds needed for gross property additions
since 1998 has been provided from operating activities. The Consolidated
Statements of Cash Flows provide additional details.

Off-Balance Sheet Financing Arrangements

At December 31, 2001, Southern Company utilized two separate financing
arrangements that are not required to be recorded on the balance sheet. In May
2001, Mississippi Power began the initial 10-year term of an operating lease
agreement signed in 1999 with Escatawpa Funding, Limited Partnership, a special
purpose entity, to use a combined-cycle generating facility located at
Mississippi Power's Plant Daniel. The facility cost approximately $370 million.
The lease provides for a residual value guarantee -- approximately 71 percent of
the completion cost -- by Mississippi Power that is due upon termination of the
lease in certain circumstances. See Note 9 to the financial statements under
"Operating Leases" for additional information regarding this lease.

   Southern Power in 2001 entered into a financial arrangement with Westdeutsche
Landesbank Girozentrale (WestLB) that is in effect until September 2002. Under
this agreement, Southern Power may assign up to $125 million in vendor contracts
for equipment to WestLB. For accounting purposes, WestLB is the owner of the
contracts. Southern Power acts as an agent for WestLB and instructs WestLB when
to make payments to the vendors. At December 31, 2001, approximately $47 million
of such vendor equipment contracts had been assigned to WestLB. Southern Power
currently anticipates terminating this arrangement and reacquiring these assets
in the first quarter of 2002.

Credit Rating Risk

Southern Company and its subsidiaries do not have any credit agreements that
would require material changes in payment schedules or terminations as a result
of a credit rating downgrade. There are contracts that could require collateral
-- but not accelerated payment -- in the event of a credit rating change to
below investment grade. These contracts are primarily for physical electricity
sales, fixed-price physical gas purchases, and agreements covering interest rate
swaps and currency swaps. At December 31, 2001, the maximum potential collateral
requirements under the electricity sale contracts were approximately $230
million. Generally, collateral may be provided for by a Southern Company
guaranty, a letter of credit, or cash. At December 31, 2001, there were no





                                     II-13



<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


material collateral requirements for the gas purchase contracts or other
financial instrument agreements.

Market Price Risk

Southern Company is exposed to market risks, including changes in interest
rates, currency exchange rates, and certain commodity prices. To manage the
volatility attributable to these exposures, the company nets the exposures to
take advantage of natural offsets and enters into various derivative
transactions for the remaining exposures pursuant to the company's policies in
areas such as counterparty exposure and hedging practices. Company policy is
that derivatives are to be used primarily for hedging purposes. Derivative
positions are monitored using techniques that include market valuation and
sensitivity analysis.

   The company's market risk exposures relative to interest rate changes have
not changed materially compared with the previous reporting period. In addition,
the company is not aware of any facts or circumstances that would significantly
affect such exposures in the near term.

   If the company sustained a 100 basis point change in interest rates for all
variable rate long-term debt, the change would affect annualized interest
expense by approximately $22 million at December 31, 2001. Based on the
company's overall interest rate exposure at December 31, 2001, including
derivative and other interest rate sensitive instruments, a near-term 100 basis
point change in interest rates would not materially affect the consolidated
financial statements.

   Due to cost-based rate regulations, the operating companies have limited
exposure to market volatility in interest rates, commodity fuel prices, and
prices of electricity. To mitigate residual risks relative to movements in
electricity prices for the operating companies, they and Southern Power enter
into fixed price contracts for the purchase and sale of electricity through the
wholesale electricity market and to a lesser extent similar contracts for gas
purchases. Also, some of the operating companies have implemented fuel-hedging
programs at the instruction of their respective public service commissions.
Realized gains and losses are recognized in the income statement as incurred. At
December 31, 2001, exposure from these activities was not material to the
consolidated financial statements. Fair value of changes in energy trading
contracts and year-end valuations are as follows:

                                       Changes During the Year
---------------------------------------------------------------
                                                    Fair Value
---------------------------------------------------------------
                                                  (in millions)
Contracts beginning of year                           $ 1.7
Contracts realized or settled                          (1.4)
New contracts                                             -
Changes in valuation techniques                           -
Current period changes                                  1.0
--------------------------------------------------------------
Contracts end of year                                 $ 1.3
==============================================================

                           Source of Year-End Valuation Prices
--------------------------------------------------------------
                                               Maturity
                             Total        -------------------
                          Fair Value      Year 1     1-3 Years
--------------------------------------------------------------
                                      (in millions)
Actively quoted             $(3.8)       $(5.1)        $1.3
External sources              5.1          5.1            -
Models and other
   methods                      -            -            -
--------------------------------------------------------------
Contracts end of year       $ 1.3        $   -         $1.3
==============================================================

   For additional information, see Note 1 to the financial statements under
"Financial Instruments."

Capital Structure

During 2001, the operating companies issued $1.2 billion of senior notes. The
majority of these proceeds was used to retire long-term debt. The companies
continued to reduce financing costs by retiring higher-cost securities.
Retirements of bonds and senior notes, including maturities, totaled $1.2
billion in 2001, $298 million during 2000, and $1.2 billion during 1999.

   Southern Company issued through the company's stock plans 17 million treasury
shares of common stock in 2001. Proceeds were $395 million and were primarily
used to reduce short-term debt. At December 31, 2001, approximately 2 million
treasury shares remain unissued.

   At the close of 2001, the company's common stock market value was $25.35 per
share, compared with book value of $11.44 per share. The market-to-book value
ratio was 222 percent at the end of 2001, compared with 212 percent at year-end
2000.



                                       II-14


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Capital Requirements for Construction

The construction program of Southern Company is budgeted at $2.8 billion for
2002, $2.1 billion for 2003, and $2.3 billion for 2004. Actual construction
costs may vary from this estimate because of changes in such factors as:
business conditions; environmental regulations; nuclear plant regulations; load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered.

   Southern Company has approximately 4,500 megawatts of new generating capacity
scheduled to be placed in service by 2003. Approximately 3,900 megawatts of
additional new capacity will be dedicated to the wholesale market and owned by
Southern Power. Significant construction of transmission and distribution
facilities and upgrading of generating plants will be continuing.

Other Capital Requirements

In addition to the funds needed for the construction program, approximately $2.4
billion will be required by the end of 2004 for present improvement fund
requirements and maturities of long-term debt. Also, the subsidiaries will
continue to retire higher-cost debt and preferred stock and replace these
obligations with lower-cost capital if market conditions permit.

   These capital requirements, lease obligations, and purchase commitments --
discussed in Notes 8 and 9 to the financial statements -- are as follows:

                                    2002      2003      2004
--------------------------------------------------------------
                                          (in millions)
Bonds -
   First mortgage                 $    7    $    -     $    -
   Pollution control                   8         -          -
Notes                                410     1,072        890
Leases -
   Capital                             4         4          4
   Operating                          74        71         70
Purchase commitments -
   Fuel                            2,399     2,185      1,541
   Purchased power                    97       100         95
--------------------------------------------------------------

   At the beginning of 2002, Southern Company had used $293 million of its
available credit arrangements. Credit arrangements are as follows:

                                           Expires
                                  ----------------------------
   Total         Unused           2002         2003 & Beyond
--------------------------------------------------------------
                           (in millions)
  $5,423         $5,130         $3,658                $1,472
--------------------------------------------------------------

Environmental Matters

On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power, and the system service company. The complaint alleges violations of the
New Source Review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the operating companies a notice of violation related
to 10 generating facilities, which includes the five facilities mentioned
previously. In early 2000, the EPA filed a motion to amend its complaint to add
the violations alleged in its notice of violation and to add Gulf Power,
Mississippi Power, and Savannah Electric as defendants. The complaint and notice
of violation are similar to those brought against and issued to several other
electric utilities. These complaints and notices of violation allege that the
utilities failed to secure necessary permits or install additional pollution
control equipment when performing maintenance and construction at coal burning-
plants constructed or under construction prior to 1978. The U.S. District Court
in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in
Georgia and granted the system service company's motion to dismiss on the
grounds that it neither owned nor operated the generating units involved in the
proceedings. The court granted the EPA's motion to add Savannah Electric as a
defendant, but it denied the motion to add Gulf Power and Mississippi Power
based on lack of jurisdiction over those companies. The court directed the EPA
to refile its amended complaint limiting claims to those brought against
Georgia Power and Savannah Electric. The EPA refiled those claims as directed
by the court. Also, the EPA refiled its claims against Alabama Power in U.S.



                                       II-15



<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


District Court in Alabama. It has not refiled against Gulf Power, Mississippi
Power, or the system service company. The Alabama Power, Georgia Power, and
Savannah Electric cases have been stayed since the spring of 2001, pending a
ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a
very similar New Source Review enforcement action against the Tennessee Valley
Authority (TVA). The TVA case involves many of the same legal issues raised by
the actions against Alabama Power, Georgia Power, and Savannah Electric. Because
the outcome of the TVA case could have a significant adverse impact on Alabama
Power and Georgia Power, both companies are parties to that case as well. The
U.S. District Court in Alabama has indicated that it will revisit the issue of a
continued stay in April 2002. The U.S. District Court in Georgia is currently
considering a motion by the EPA to reopen the Georgia case. Georgia Power and
Savannah Electric have opposed that motion.

   Southern Company believes that its operating companies complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome in any
one of these cases could require substantial capital expenditures that cannot be
determined at this time and could possibly require payment of substantial
penalties. This could affect future results of operations, cash flows, and
possibly financial condition if such costs are not recovered through regulated
rates.

   In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company. Reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
were required in two phases. Phase I compliance began in 1995. Southern Company
achieved Phase I compliance at its affected plants by primarily switching to
low-sulfur coal and with some equipment upgrades. Construction expenditures for
Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled
approximately $300 million. Phase II sulfur dioxide compliance was required in
2000. Southern Company used emission allowances and fuel switching to comply
with Phase II requirements. Also, equipment to control nitrogen oxide emissions
was installed on additional system fossil-fired units as necessary to meet Phase
II limits and ozone non-attainment requirements for metropolitan Atlanta through
2000. Compliance for Phase II and initial ozone non-attainment requirements
increased total construction expenditures through 2000 by approximately $100
million.

   Respective state plans to address the one-hour ozone non-attainment standards
for the Atlanta and Birmingham areas have been established and must be
implemented in May 2003. Seven generating plants in the Atlanta area and two
plants in the Birmingham area will be affected. Construction expenditures for
compliance with these new rules are currently estimated at approximately $940
million, of which $520 million remains to be spent.

   A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.

   In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA. In addition, the Federal District of
Columbia Circuit Court of Appeals is considering other legal challenges to these
standards. A court decision is expected in the spring of 2002. If the standards
are eventually upheld, implementation could be required by 2007 to 2010.

   In September 1998, the EPA issued regional nitrogen oxide reduction rules to
the states for implementation. The final rule affects 21 states, including
Alabama and Georgia. Compliance is required by May 31, 2004, for most states,
including Alabama. For Georgia, further rulemaking was required, and proposed
compliance was delayed until May 1, 2005. Additional construction expenditures
for compliance with these new rules are currently estimated at approximately
$190 million.

   In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and the regulations are scheduled to be finalized by the end
of 2004 with implementation to take place around 2007. In January 2001, the EPA





                                       II-16


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional
Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.

   Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.

   In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and the utility industry. Generally, this rule affects the operation and
maintenance of electrostatic precipitators and could involve significant
additional ongoing expense.

   The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.

   Southern Company must comply with other environmental laws and regulations
that cover the handling and disposal of hazardous waste. Under these various
laws and regulations, the subsidiaries could incur substantial costs to clean up
properties. The subsidiaries conduct studies to determine the extent of any
required cleanup and have recognized in their respective financial statements
costs to clean up known sites. These costs for Southern Company amounted to $1
million in 2001 and $4 million in both 2000 and 1999. Additional sites may
require environmental remediation for which the subsidiaries may be liable for a
portion or all required cleanup costs. See Note 3 to the financial statements
for information regarding Georgia Power's potentially responsible party status
at sites in Georgia.

   Several major pieces of environmental legislation are periodically considered
for reauthorization or amendment by Congress. These include: the Clean Air Act;
the Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of Southern Company's operations. The full impact of any such changes
cannot be determined at this time.

   Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Southern Company. The impact of new legislation -- if
any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential exists for liability as the
result of lawsuits alleging damages caused by electromagnetic fields.

Sources of Capital

The amount and timing of additional equity capital to be raised in 2002 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital can be provided from any combination of
public offerings, private placements, or the company's stock plans.

   The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources. However, the type and timing of any financings
-- if needed -- will depend on market conditions and regulatory approval. In
recent years, financings primarily have utilized unsecured debt and trust
preferred securities.

   Southern Power will use both external funds and equity capital from Southern
Company to finance its construction program.

   To meet short-term cash needs and contingencies, Southern Company had at the
beginning of 2002 approximately $354 million of cash and cash equivalents and
$5.1 billion of unused credit arrangements with banks.





                                       II-17




<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Cautionary Statement Regarding
Forward-Looking Information

Southern Company's 2001 Annual Report includes forward-looking statements in
addition to historical information. Forward-looking information includes, among
other things, statements concerning the strategic goals for Southern Company's
new wholesale business and also Southern Company's goals for dividend payout
ratio, earnings per share, and earnings growth. In some cases, forward-looking
statements can be identified by terminology such as "may," "will," "could,"
"should," "expects," "plans," "anticipates," "believes," "estimates,"
"projects," "predicts," "potential," or "continue" or the negative of these
terms or other comparable terminology. Southern Company cautions that there are
various important factors that could cause actual results to differ materially
from those indicated in the forward-looking statements; accordingly, there can
be no assurance that such indicated results will be realized. These factors
include the impact of recent and future federal and state regulatory change,
including legislative and regulatory initiatives regarding deregulation and
restructuring of the electric utility industry, and also changes in
environmental and other laws and regulations to which Southern Company and its
subsidiaries are subject, as well as changes in application of existing laws
and regulations; current and future litigation, including the pending EPA civil
action against certain Southern Company subsidiaries and the race discrimination
litigation against certain Southern Company subsidiaries; the effects, extent,
and timing of the entry of additional competition in the markets in which
Southern Company's subsidiaries operate; the impact of fluctuations in
commodity prices, interest rates, and customer demand; state and federal rate
regulations; political, legal, and economic conditions and developments in the
United States; the performance of projects undertaken by the non-traditional
business and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets
or businesses, which cannot be assured to be completed or beneficial to Southern
Company or its subsidiaries; the effects of, and changes in, economic conditions
in the areas in which Southern Company's subsidiaries operate; the direct or
indirect effects on Southern Company's business resulting from the terrorist
incidents on September 11, 2001, or any similar such incidents or responses to
such incidents; financial market conditions and the results of financing
efforts; the timing and acceptance of Southern Company's new product and service
offerings; the ability of Southern Company to obtain additional generating
capacity at competitive prices; weather and other natural phenomena; and other
factors discussed elsewhere herein and in other reports (including the Form
10-K) filed from time to time by Southern Company with the Securities and
Exchange Commission.




                                       II-18

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report

------------------------------------------------------------------------------------------------------------------------------
                                                                                 2001                 2000              1999
------------------------------------------------------------------------------------------------------------------------------
                                                                                                (in millions)
Operating Revenues:
<S>                                                                          <C>                  <C>                 <C>
Retail sales                                                                 $  8,440             $  8,600            $8,090
Sales for resale                                                                1,174                  977               823
Other revenues                                                                    541                  489               404
------------------------------------------------------------------------------------------------------------------------------
Total operating revenues                                                       10,155               10,066             9,317
------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel                                                                            2,577                2,564             2,328
Purchased power                                                                   718                  677               409
Other operations                                                                1,852                1,861             1,838
Maintenance                                                                       909                  852               829
Depreciation and amortization                                                   1,173                1,171             1,139
Taxes other than income taxes                                                     535                  536               523
------------------------------------------------------------------------------------------------------------------------------
Total operating expenses                                                        7,764                7,661             7,066
------------------------------------------------------------------------------------------------------------------------------
Operating Income                                                                2,391                2,405             2,251
Other Income:
Interest income                                                                    27                   29                30
Other, net                                                                          3                  (21)              (45)
------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations
  Before Interest and Income Taxes                                              2,421                2,413             2,236
------------------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net                                                             557                  643               527
Distributions on capital and preferred securities of subsidiaries                 169                  169               175
Preferred dividends of subsidiaries                                                18                   19                20
------------------------------------------------------------------------------------------------------------------------------
Total interest and other                                                          744                  831               722
------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before Income Taxes                         1,677                1,582             1,514
Income taxes                                                                      558                  588               599
------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before
  Cumulative Effect of Accounting Change                                        1,119                  994               915
Cumulative effect of accounting change --
  less income taxes of less than $1                                                 1                    -                 -
------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations                                             1,120                  994               915
Earnings from discontinued operations,
  net of income taxes of $93, $86, and $127
  for 2001, 2000, and 1999, respectively                                          142                  319               361
------------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income                                                      $  1,262             $  1,313            $1,276
==============================================================================================================================
Common Stock Data:
Earnings per share from continuing operations -
  Basic                                                                         $1.62                $1.52             $1.33
  Diluted                                                                        1.61                 1.52              1.33
Earnings per share including discontinued operations -
  Basic                                                                         $1.83                $2.01             $1.86
  Diluted                                                                        1.82                 2.01              1.86
------------------------------------------------------------------------------------------------------------------------------
Average number of shares of common stock outstanding - (in millions)
  Basic                                                                           689                  653               685
  Diluted                                                                         694                  654               686
------------------------------------------------------------------------------------------------------------------------------
Cash dividends paid per share of common stock                                   $1.34                $1.34             $1.34
------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>



                                                                II-19
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report

------------------------------------------------------------------------------------------------------------------------------
                                                                                 2001                 2000              1999
------------------------------------------------------------------------------------------------------------------------------
                                                                                                (in millions)
Operating Activities:
<S>                                                                           <C>                  <C>               <C>
Consolidated net income                                                       $ 1,262              $ 1,313           $ 1,276
Adjustments to reconcile consolidated net income
   to net cash provided from operating activities --
      Less income from discontinued operations                                    142                  319               361
      Depreciation and amortization                                             1,358                1,337             1,216
      Deferred income taxes and investment tax credits                            (22)                  97                10
      Other, net                                                                 (192)                  18               118
      Changes in certain current assets and liabilities --
           Receivables, net                                                       344                 (379)             (141)
           Fossil fuel stock                                                     (199)                  78               (41)
           Materials and supplies                                                 (43)                 (15)              (37)
           Accounts payable                                                       (51)                 180               (65)
           Other                                                                   69                   66               244
------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities of continuing operations            2,384                2,376             2,219
------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                                       (2,617)              (2,225)           (1,881)
Other                                                                            (119)                 (81)             (362)
------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities of continuing operations                (2,736)              (2,306)           (2,243)
------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                         223                 (275)              831
Proceeds --
   Long-term senior notes                                                       1,242                  650               840
   Other long-term debt                                                           757                   93               629
   Capital and preferred securities                                                30                    -               250
   Common stock                                                                   395                  910                24
Redemptions --
   First mortgage bonds                                                          (616)                (211)             (890)
   Other long-term debt                                                          (569)                (204)             (483)
   Capital and preferred securities                                                 -                    -              (100)
   Preferred stock                                                                  -                    -               (86)
   Common stock repurchased                                                         -                 (415)             (862)
Payment of common stock dividends                                                (922)                (873)             (921)
Other                                                                             (33)                 (54)              (50)
------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for)
  financing activities of continuing operations                                   507                 (379)             (818)
------------------------------------------------------------------------------------------------------------------------------
Cash provided from (used for) discontinued operations                               -                  354               684
------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                              155                   45              (158)
Cash and Cash Equivalents at Beginning of Year                                    199                  154               312
------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                      $   354              $   199           $   154
==============================================================================================================================
Supplemental Cash Flow Information
  From Continuing Operations:
Cash paid during the year for --
   Interest (net of amount capitalized)                                          $624                 $802              $684
   Income taxes                                                                  $721                 $666              $656
------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                II-20

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report

-------------------------------------------------------------------------------------------------------------------
Assets                                                                               2001                    2000
-------------------------------------------------------------------------------------------------------------------
                                                                                            (in millions)
Current Assets:
<S>                                                                              <C>                    <C>
Cash and cash equivalents                                                         $   354                 $   199
Special deposits                                                                       23                       6
Receivables, less accumulated provisions for uncollectible accounts
   of $24 in 2001 and $22 in 2000                                                   1,132                   1,312
Under recovered retail fuel clause revenue                                            280                     418
Fossil fuel stock, at average cost                                                    394                     195
Materials and supplies, at average cost                                               550                     507
Other                                                                                 223                     188
-------------------------------------------------------------------------------------------------------------------
Total current assets                                                                2,956                   2,825
-------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service                                                                         35,813                  34,188
Less accumulated depreciation                                                      15,020                  14,350
-------------------------------------------------------------------------------------------------------------------
                                                                                   20,793                  19,838
Nuclear fuel, at amortized cost                                                       202                     215
Construction work in progress                                                       2,089                   1,569
-------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                               23,084                  21,622
-------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Nuclear decommissioning trusts, at fair value                                         682                     690
Net assets of discontinued operations                                                   -                   3,320
Leveraged leases                                                                      655                     596
Other                                                                                 193                     161
-------------------------------------------------------------------------------------------------------------------
Total other property and investments                                                1,530                   4,767
-------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes                                              924                     957
Prepaid pension costs                                                                 547                     398
Debt expense, being amortized                                                         103                      99
Premium on reacquired debt, being amortized                                           280                     280
Other                                                                                 400                     312
-------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                             2,254                   2,046
-------------------------------------------------------------------------------------------------------------------
Total Assets                                                                      $29,824                 $31,260
===================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>

                                                                II-21


<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity                                               2001                    2000
-----------------------------------------------------------------------------------------------------------------
                                                                                           (in millions)
Current Liabilities:
<S>                                                                           <C>                    <C>
Securities due within one year                                                  $   429                 $    67
Notes payable                                                                     1,902                   1,680
Accounts payable                                                                    847                     869
Customer deposits                                                                   153                     140
Taxes accrued --
   Income taxes                                                                     160                      88
   Other                                                                            193                     208
Interest accrued                                                                    118                     121
Vacation pay accrued                                                                125                     119
Other                                                                               445                     426
-----------------------------------------------------------------------------------------------------------------
Total current liabilities                                                         4,372                   3,718
-----------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                      8,297                   7,843
-----------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes                                                 4,088                   4,074
Deferred credits related to income taxes                                            500                     551
Accumulated deferred investment tax credits                                         634                     664
Employee benefits provisions                                                        450                     401
Prepaid capacity revenues                                                            41                      58
Other                                                                               814                     647
----------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                      6,527                   6,395
----------------------------------------------------------------------------------------------------------------
Company or subsidiary obligated mandatorily redeemable
   capital and preferred securities (See accompanying statements)                 2,276                   2,246
----------------------------------------------------------------------------------------------------------------
Cumulative preferred stock of subsidiaries (See accompanying statements)            368                     368
----------------------------------------------------------------------------------------------------------------
Common stockholders' equity (See accompanying statements)                         7,984                  10,690
----------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity                                      $29,824                 $31,260
================================================================================================================
Commitments and Contingent Matters (Notes 1, 2, 3, 5, 8, 9, and 10)
----------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these balance sheets.

</TABLE>

                                                                II-22


<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED SATEEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report

----------------------------------------------------------------------------------------------------------------------------
                                                                 2001             2000              2001              2000
----------------------------------------------------------------------------------------------------------------------------
                                                                     (in millions)                    (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
   Maturity                        Interest Rates
   --------                        --------------
<S>                                <C>                        <C>              <C>                 <C>              <C>
   2003                            6.13% to 6.63%             $     -          $   325
   2004                            6.60%                            -               35
   2005                            6.07%                            2               10
   2006                            6.50% to 6.90%                  45               45
   2007 through 2011               6.88%                            -               50
   2021 through 2025               6.88% to 9.00%                 437              635
   2026 through 2030               6.88%                           30               30
----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                        514            1,130
----------------------------------------------------------------------------------------------------------------------------
Long-term senior notes payable --
   4.69% to 9.75% due 2002-2005                                 1,834              766
   5.38% to 8.58% due 2006-2009                                   595              744
   6.10% to 7.63% due 2010-2017                                   305              170
   6.38% to 8.12% due 2018-2038                                   788              793
   6.63% to 7.13% due 2039-2048                                 1,029            1,029
   Adjustable rates (1.98% to 3.44% at 1/1/02)
      due 2002-2005                                             1,078              734
----------------------------------------------------------------------------------------------------------------------------
Total long-term senior notes payable                            5,629            4,236
----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
   Pollution control revenue bonds --
      Collateralized:
         5.00% to 6.75% due 2005-2026                             168              539
         Variable rates (1.61% to 1.95% at 1/1/02)
           due 2015-2025                                           90               90
      Non-collateralized:
         4.20% to 6.75% due 2015-2034                             726              406
         Variable rates (1.75% to 2.05% at 1/1/02)
           due 2011-2037                                        1,566            1,475
----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                      2,550            2,510
----------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations                                      92               95
----------------------------------------------------------------------------------------------------------------------------
Unamortized debt (discount), net                                  (59)             (61)
----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
   requirement -- $443 million)                                 8,726            7,910
Less amount due within one year                                   429               67
----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year             8,297            7,843              43.9%             37.1%
----------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                                                II-23
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Southern Company and Subsidiary Companies 2001 Annual Report

---------------------------------------------------------------------------------------------------------------------------
                                                                2001             2000              2001              2000
---------------------------------------------------------------------------------------------------------------------------
                                                                    (in millions)                    (percent of total)
Company or Subsidiary Obligated Mandatorily
   Redeemable Capital and Preferred Securities:
$25 liquidation value --
   <S>                                                          <C>              <C>            <C>             <C>
   6.85% to 7.00%                                                435              435
   7.13% to 7.38%                                                327              297
   7.60% to 7.63%                                                415              415
   7.75%                                                         649              649
   8.14% to 8.19%                                                400              400
   Auction rate (3.60% at 1/1/02)                                 50               50
---------------------------------------------------------------------------------------------------------------------------
Total company or subsidiary obligated mandatorily
   redeemable capital and preferred securities (annual
   distribution requirement -- $170 million)                   2,276            2,246              12.0              10.6
---------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
   4.20% to 7.00%                                                 98               98
$25 par or stated value --
   5.20% to 5.83%                                                200              200
Adjustable and auction rates -- at 1/1/02:
   3.10% to 3.56%                                                 70               70
---------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock of subsidiaries
  (annual dividend requirement -- $18 million)                   368              368               1.9               1.7
---------------------------------------------------------------------------------------------------------------------------
Common Stockholders' Equity:
Common stock, par value $5 per share --
   Authorized -- 1 billion shares
   Issued -- 2001:   701 million shares
          -- 2000:   701 million shares
   Treasury -- 2001:   2 million shares
             -- 2000:  19 million shares
   Par value                                                   3,503            3,503
   Paid-in capital                                                14            3,153
   Treasury, at cost                                             (57)            (545)
Retained earnings                                              4,517            4,672
Accumulated other comprehensive income --
  From continuing operations                                       7                -
  From discontinued operations                                     -              (93)
---------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity                              7,984           10,690              42.2              50.6
---------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                         $18,925          $21,147             100.0%            100.0%
===========================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>


                                                                II-24

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report

                                                                                                    Accumulated
                                                                                                Other Comprehensive
                                                 Common Stock                                       Income From
                                           --------------------------                 -----------------------------
                                           Par     Paid-In                Retained    Continuing      Discontinued
                                          Value    Capital   Treasury     Earnings    Operations       Operations       Total
-------------------------------------------------------------------------------------------------------------------------------
                                                                            (in millions)

<S>                                     <C>       <C>         <C>         <C>             <C>           <C>         <C>
Balance at December 31, 1998             $3,499    $2,463      $ (58)      $3,878          $  -           $  15      $  9,797
Net income                                    -         -          -        1,276             -               -         1,276
Other comprehensive income                    -         -          -            -             -            (107)         (107)
Stock issued                                  4        17          1            -             -               -            22
Stock repurchased, at cost                    -         -       (861)           -             -               -          (861)
Cash dividends                                -         -          -         (921)            -               -          (921)
Other                                         -         -         (1)          (1)            -               -            (2)
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999              3,503     2,480       (919)       4,232             -             (92)        9,204
Net income                                    -         -          -        1,313             -               -         1,313
Other comprehensive income                    -         -          -            -             -              (1)           (1)
Stock issued                                  -       121        789            -             -               -           910
Stock repurchased, at cost                    -         -       (414)           -             -               -          (414)
Cash dividends                                -         -          -         (873)            -               -          (873)
Other                                         -       552         (1)           -             -               -           551
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000              3,503     3,153       (545)       4,672             -             (93)       10,690
Net income                                    -         -          -        1,262             -               -         1,262
Other comprehensive income                    -         -          -            -             7              93           100
Stock issued                                  -         -        488          (93)            -               -           395
Mirant spin off distribution                  -    (3,168)         -         (391)            -               -        (3,559)
Cash dividends                                -         -          -         (922)            -               -          (922)
Other                                         -        29          -          (11)            -               -            18
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001             $3,503   $    14      $ (57)      $4,517           $ 7           $   -      $  7,984
===============================================================================================================================

</TABLE>

<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Southern Company and Subsidiary Companies 2001 Annual Report

--------------------------------------------------------------------------------------------------------------------------
                                                                                         2001          2000         1999
--------------------------------------------------------------------------------------------------------------------------
                                                                                             (in millions)

<S>                                                                                    <C>           <C>          <C>
Consolidated Net Income                                                                $1,262        $1,313       $1,276
--------------------------------------------------------------------------------------------------------------------------
Other comprehensive income -- continuing operations:
   Changes in fair value of qualifying cash flow hedges, net of tax of $4                   7             -            -
--------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income -- continuing operations                                   7             -            -
--------------------------------------------------------------------------------------------------------------------------
Other comprehensive income -- discontinued operations:
   Cumulative effect of accounting change for qualifying hedges, net of tax of $(121)    (249)            -            -
   Changes in fair value of qualifying hedges, net of tax of $(51)                       (104)            -            -
   Less: Reclassification adjustment for amounts
      included in net income, net of tax of $29                                            60             -            -
   Foreign currency translation adjustments, net of tax of $(22), $(1), and $(58)
      for the years 2001, 2000, and 1999, respectively                                    (22)           (1)        (107)
--------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income -- discontinued operations                              (315)           (1)        (107)
--------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income                                                      $  954        $1,312       $1,169
==========================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                                II-25


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2001 Annual Report


1. Summary of Significant Accounting
   Policies

General

Southern Company is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern LINC), Southern
Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern
Power), and other direct and indirect subsidiaries. The operating companies --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- provide electric service in four Southeastern states. Contracts
among the operating companies -- related to jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. The system service company provides, at
cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Power was established in 2001 to construct, own, and manage Southern
Company's competitive generation assets and sell electricity at market-based
rates in the wholesale market.

   On April 2, 2001, the spin off of Mirant Corporation (Mirant) was completed.
As a result of the spin off, Southern Company's financial statements and related
information reflect Mirant as discontinued operations. For additional
information, see Note 11.

   The financial statements reflect Southern Company's investments in the
subsidiaries on a consolidated basis. All material intercompany items have been
eliminated in consolidation. Certain prior years' data presented in the
consolidated financial statements have been reclassified to conform with the
current year presentation.

   Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both the company and its subsidiaries are
subject to the regulatory provisions of the PUHCA. The operating companies also
are subject to regulation by the FERC and their respective state public service
commissions. The companies follow accounting principles generally accepted in
the United States and comply with the accounting policies and practices
prescribed by their respective commissions. The preparation of financial
statements in conformity with accounting principles generally accepted in the
U.S. requires the use of estimates, and the actual results may differ from those
estimates.

Regulatory Assets and Liabilities

The operating companies are subject to the provisions of Financial Accounting
Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain
Types of Regulation. Regulatory assets represent probable future revenues
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Consolidated Balance Sheets at December 31 relate to the
following:

                                           2001           2000
---------------------------------------------------------------
                                             (in millions)
Deferred income tax charges               $ 924          $ 957
Premium on reacquired debt                  280            280
Department of Energy assessments             39             46
Vacation pay                                 95             92
Postretirement benefits                      28             30
Deferred income tax credits                (500)          (551)
Accelerated amortization                   (311)          (220)
Storm damage reserves                       (34)           (34)
Other, net                                  125            121
---------------------------------------------------------------
Total                                     $ 646          $ 721
===============================================================

   In the event that a portion of a company's operations is no longer subject to
the provisions of FASB Statement No. 71, the company would be required to write
off related regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.

Revenues and Fuel Costs

Revenues are recognized as services are rendered. Unbilled revenues are accrued
at the end of each fiscal period. Fuel costs are expensed as the fuel is used.
Electric rates for the operating companies include provisions to adjust billings
for fluctuations in fuel costs, the energy component of purchased power costs,
and certain other costs. Revenues are adjusted for differences between


                                       II-26
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


recoverable fuel costs and amounts actually recovered in current regulated
rates.

   Southern Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts continued to average less than 1 percent of revenues.

   Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $133
million in 2001, $136 million in 2000, and $137 million in 1999. Alabama Power
and Georgia Power have contracts with the U.S. Department of Energy (DOE) that
provide for the permanent disposal of spent nuclear fuel. The DOE failed to
begin disposing of spent nuclear fuel in January 1998 as required by the
contracts, and the companies are pursuing legal remedies against the government
for breach of contract. Sufficient pool storage capacity for spent fuel is
available at Plant Farley to maintain full-core discharge capability until the
refueling outages scheduled for 2006 and 2008 for units 1 and 2, respectively.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to
maintain full-core discharge capability for both units into 2014. At Plant
Hatch, an on-site dry storage facility became operational in 2000. Sufficient
dry storage capacity is believed to be available to continue dry storage
operations at Plant Hatch through the life of the plant. Procurement of on-site
dry storage capacity at Plant Farley is in progress, with the intent to place
the capacity in operation in 2005. Procurement of on-site dry storage capacity
at Plant Vogtle will begin in sufficient time to maintain pool full-core
discharge capability.

   Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is funded in part by
a special assessment on utilities with nuclear plants. This assessment is being
paid over a 15-year period, which began in 1993. This fund will be used by the
DOE for the decontamination and decommissioning of its nuclear fuel enrichment
facilities. The law provides that utilities will recover these payments in the
same manner as any other fuel expense. Alabama Power and Georgia Power -- based
on its ownership interests -- estimate their respective remaining liability at
December 31, 2001, under this law to be approximately $21 million and $16
million. These obligations are recorded in the Consolidated Balance Sheets.

Depreciation and Nuclear Decommissioning

Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.4 percent a year in
2001, 2000, and 1999. When property subject to depreciation is retired or
otherwise disposed of in the normal course of business, its original cost --
together with the cost of removal, less salvage -- is charged to accumulated
depreciation. Minor items of property included in the original cost of the plant
are retired when the related property unit is retired. Depreciation expense
includes an amount for the expected costs of decommissioning nuclear facilities
and removal of other facilities.

   Georgia Power recorded accelerated amortization and depreciation amounting to
$91 million in 2001, $135 million in 2000, and $85 million in 1999. See Note 3
under "Georgia Power Retail Rate Orders" for additional information.

   The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial nuclear power reactors to establish a plan for providing, with
reasonable assurance, funds for decommissioning. Alabama Power and Georgia Power
have external trust funds to comply with the NRC's regulations. Amounts
previously recorded in internal reserves are being transferred into the external
trust funds over periods approved by the respective state public service
commissions. The NRC's minimum external funding requirements are based on a
generic estimate of the cost to decommission the radioactive portions of a
nuclear unit based on the size and type of reactor. Alabama Power and Georgia
Power have filed plans with the NRC to ensure that -- over time -- the deposits
and earnings of the external trust funds will provide the minimum funding
amounts prescribed by the NRC.

   Site study cost is the estimate to decommission a specific facility as of the
site study year, and ultimate cost is the estimate to decommission a specific
facility as of its retirement date. The estimated costs of decommissioning --
both site study costs and ultimate costs -- based on the most current study as


                                       II-27
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


of December 31, 2001, for Alabama Power's Plant Farley and Georgia Power's
ownership interests in plants Hatch and Vogtle were as follows:

                                   Plant      Plant      Plant
                                  Farley      Hatch     Vogtle
----------------------------------------------------------------
Site study basis (year)             1998       2000       2000
Decommissioning periods:
   Beginning year                   2017       2014       2027
   Completion year                  2031       2042       2045
----------------------------------------------------------------
                                        (in millions)
Site study costs:
   Radiated structures              $629       $486       $420
   Non-radiated structures            60         37         48
----------------------------------------------------------------
Total                               $689       $523       $468
================================================================
                                        (in millions)
Ultimate costs:
   Radiated structures            $1,868     $1,004     $1,468
   Non-radiated structures           178         79        166
----------------------------------------------------------------
Total                             $2,046     $1,083     $1,634
================================================================

Significant assumptions:
   Inflation rate                    4.5%       4.7%       4.7%
   Trust earning rate                7.0        6.5        6.5
----------------------------------------------------------------

   The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making these estimates.

   Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 2001 and fund balances were as follows:

                                   Plant      Plant      Plant
                                  Farley      Hatch     Vogtle
-----------------------------------------------------------------
                                        (in millions)
Amount expensed in 2001            $  18      $  20     $    9
Accumulated provisions:
   External trust funds,
      at fair value                 $318       $229       $135
   Internal reserves                  36         20         12
-----------------------------------------------------------------
Total                               $354       $249       $147
=================================================================

   Alabama Power's decommissioning costs for ratemaking are based on the site
study. Effective January 1, 2002, the Georgia Public Service Commission (GPSC)
decreased Georgia Power's annual provision for decommissioning expenses to $8
million. This amount is based on the NRC generic estimate to decommission the
radioactive portion of the facilities as of 2000. The estimates are $383 million
and $282 million for plants Hatch and Vogtle, respectively. The ultimate costs
associated with the 2000 NRC minimum funding requirements are $823 million and
$1.03 billion for plants Hatch and Vogtle, respectively. Alabama Power and
Georgia Power expect their respective state public service commissions to
periodically review and adjust, if necessary, the amounts collected in rates for
the anticipated cost of decommissioning.

   In January 2002, Georgia Power received NRC approval for a 20-year extension
of the license at Plant Hatch, which would permit the operation of units 1 and 2
until 2034 and 2038, respectively. The decommissioning costs disclosed above do
not reflect this extension.

Income Taxes

Southern Company uses the liability method of accounting for deferred income
taxes and provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory
disallowances and impairments. Original cost includes: materials; labor; minor
items of property; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the estimated cost of
funds used during construction. The cost of funds capitalized was $67 million in
2001, $71 million in 2000, and $36 million in 1999. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense as incurred or performed. The cost of replacements of property --
exclusive of minor items of property -- is capitalized.

Leveraged Leases

Southern Company has several leveraged lease agreements -- ranging up to 30
years -- that relate to international energy generation, distribution, and
transportation assets. Southern Company receives federal income tax deductions
for depreciation and amortization and for interest on long-term debt related to
these investments.


                                       II-28
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


   Southern Company's net investment in leveraged leases consists of the
following at December 31:

                                           2001           2000
------------------------------------------------------------------
                                             (in millions)
Net rentals receivable                   $1,430         $1,430
Unearned income                            (775)          (834)
------------------------------------------------------------------
Investment in leveraged leases              655            596
Deferred taxes arising
  from leveraged leases                    (193)          (128)
------------------------------------------------------------------
Net investment in leveraged leases       $  462         $  468
==================================================================

   A summary of the components of income from leveraged leases is as follows:

                                    2001      2000      1999
------------------------------------------------------------------
                                          (in millions)
Pretax leveraged lease income        $59       $61        $28
Income tax expense                    21        21         10
------------------------------------------------------------------
Income from leveraged leases         $38       $40        $18
==================================================================

Impairment of Long-Lived Assets and Intangibles

Southern Company evaluates long-lived assets for impairment when events or
changes in circumstances indicate that the carrying value of such assets may not
be recoverable. The determination of whether an impairment has occurred is based
on an estimate of undiscounted future cash flows attributable to the assets, as
compared with the carrying value of the assets. If an impairment has occurred,
the amount of the impairment recognized is determined by estimating the fair
value of the assets and recording a provision for loss if the carrying value is
greater than the fair value. For assets identified as held for sale, the
carrying value is compared to the estimated fair value less the cost to sell in
order to determine if an impairment provision is required. Until the assets are
disposed of, their estimated fair value is reevaluated when circumstances or
events change.

Cash and Cash Equivalents

For purposes of the consolidated financial statements, temporary cash
investments are considered cash equivalents. Temporary cash investments are
securities with original maturities of 90 days or less.

Materials and Supplies

Generally, materials and supplies include the costs of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.

Comprehensive Income

Comprehensive income -- consisting of net income and changes in the fair value
of marketable securities and qualifying cash flow hedges, net of income taxes --
is presented in the consolidated financial statements. Also, comprehensive
income from discontinued operations includes foreign currency translation
adjustments, net of income taxes. The objective of comprehensive income is to
report a measure of all changes in common stock equity of an enterprise that
result from transactions and other economic events of the period other than
transactions with owners.

Financial Instruments

Effective January 2001, Southern Company adopted FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended. The
impact on net income was immaterial.

   Southern Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, and certain
commodity prices. Gains and losses on qualifying hedges are deferred and
recognized either in income or as an adjustment to the carrying amount of the
hedged item when the transaction occurs. At December 31, 2001, Southern Company
had $450 million notional amount of interest rate swaps outstanding with
deferred gains of $12 million.

   Southern Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the company's exposure to counterparty credit risk.

   The operating companies and Southern Power enter into commodity related
forward and option contracts to limit exposure to changing prices on certain
fuel purchases and electricity purchases and sales. Substantially all of
Southern Company's bulk energy purchases and sales contracts meet the definition
of a derivative under FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities. In many cases, these fuel and electricity
contracts qualify for normal purchase and sale exceptions under Statement No.
133 and are accounted for under the accrual method. Other contracts qualify as
cash flow hedges of anticipated transactions, resulting in the deferral of
related gains and losses, and are recorded in other comprehensive income until
the hedged transactions occur. Any ineffectiveness is recognized currently in


                                       II-29
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


net income. Contracts that do not qualify for the normal purchase and sale
exception and that do not meet the hedge requirements are marked to market
through current period income.

   Southern Company has firm purchase commitments for equipment that require
payment in euros. As a hedge against fluctuations in the exchange rate for
euros, the company entered into forward currency swaps. The total notional
amount is 48 million euros maturing in 2002 and 2003. At December 31, 2001, the
gain on these swaps was less than $1 million.

   Other Southern Company financial instruments for which the carrying amount
did not equal fair value at December 31 were as follows:

                                       Carrying           Fair
                                         Amount          Value
----------------------------------------------------------------
                                            (in millions)
Long-term debt:
   At December 31, 2001                  $8,634         $8,693
   At December 31, 2000                   7,815          7,702
Capital and preferred securities:
   At December 31, 2001                   2,276          2,282
   At December 31, 2000                   2,246          2,190
----------------------------------------------------------------

   The fair values for long-term debt and capital and preferred securities were
based on either closing market price or closing price of comparable instruments.

2. RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. Also, Southern Company provides certain medical
care and life insurance benefits for retired employees. The operating companies
fund trusts to the extent required by their respective regulatory commissions.
In late 2000, Southern Company adopted several pension and postretirement
benefit plan changes that had the effect of increasing benefits to both current
and future retirees.

   The measurement date for plan assets and obligations is September 30 for each
year. The following disclosures exclude discontinued operations.

Pension Plan

Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:

                                                Projected
                                           Benefit Obligations
                                          ----------------------
                                             2001         2000
----------------------------------------------------------------
                                                (in millions)
Balance at beginning of year               $3,397       $3,248
Service cost                                  104           96
Interest cost                                 260          239
Benefits paid                                (176)        (159)
Plan amendments                               173            4
Actuarial (gain) loss                           2          (31)
----------------------------------------------------------------
Balance at end of year                     $3,760       $3,397
================================================================

                                               Plan Assets
                                          ----------------------
                                             2001         2000
----------------------------------------------------------------
                                                (in millions)
Balance at beginning of year               $6,157       $5,266
Actual return on plan assets                 (889)       1,030
Benefits paid                                (159)        (139)
----------------------------------------------------------------
Balance at end of year                     $5,109       $6,157
================================================================

   The accrued pension costs recognized in the Consolidated Balance Sheets were
as follows:

                                             2001         2000
------------------------------------------------------------------
                                                (in millions)
Funded status                             $ 1,349      $ 2,760
Unrecognized transition obligation            (51)         (63)
Unrecognized prior service cost               269          116
Unrecognized net gain                      (1,020)      (2,415)
------------------------------------------------------------------
Prepaid asset recognized in the
   Consolidated Balance Sheets            $   547      $   398
==================================================================

   Components of the pension plan's net periodic cost were as follows:

                                    2001      2000       1999
----------------------------------------------------------------
                                          (in millions)
Service cost                       $ 104   $    96     $   97
Interest cost                        260       239        215
Expected return on
   plan assets                      (423)     (384)      (348)
Recognized net gain                  (73)      (62)       (40)
Net amortization                       8         -         (2)
----------------------------------------------------------------
Net pension cost (income)          $(124)    $(111)    $  (78)
================================================================


                                       II-30
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:

                                               Accumulated
                                           Benefit Obligations
                                           ----------------------
                                             2001         2000
-----------------------------------------------------------------
                                                (in millions)
Balance at beginning of year               $1,052       $  980
Service cost                                   22           18
Interest cost                                  88           76
Benefits paid                                 (54)         (43)
Plan amendments                               186           69
Actuarial (gain) loss                         (55)         (48)
-----------------------------------------------------------------
Balance at end of year                     $1,239       $1,052
=================================================================

                                               Plan Assets
                                             --------------------
                                             2001         2000
-----------------------------------------------------------------
                                                (in millions)
Balance at beginning of year                 $459         $395
Actual return on plan assets                  (59)          47
Employer contributions                         79           59
Benefits paid                                 (54)         (42)
-----------------------------------------------------------------
Balance at end of year                       $425         $459
=================================================================

   The accrued postretirement costs recognized in the Consolidated Balance
Sheets were as follows:

                                             2001         2000
-----------------------------------------------------------------
                                                (in millions)
Funded status                               $(814)       $(593)
Unrecognized transition obligation            174          189
Unrecognized prior service cost               239           66
Unrecognized net loss (gain)                   (9)         (53)
Fourth quarter contributions                   41           35
-----------------------------------------------------------------
Accrued liability recognized in the
   Consolidated Balance Sheets              $(369)       $(356)
=================================================================

   Components of the postretirement plan's net periodic cost were as follows:


                                    2001      2000      1999
--------------------------------------------------------------
                                          (in millions)
Service cost                        $ 22      $ 18       $ 21
Interest cost                         88        76         68
Expected return on
   plan assets                       (40)      (34)       (26)
Recognized net gain                    -         -          2
Net amortization                      26        18         15
--------------------------------------------------------------
Net postretirement cost             $ 96      $ 78       $ 80
==============================================================

   The weighted average rates assumed in the actuarial calculations for both the
pension plan and postretirement benefits plan were:

                                             2001         2000
-----------------------------------------------------------------
Discount                                     7.50%        7.50%
Annual salary increase                       5.00         5.00
Long-term return on plan assets              8.50         8.50
-----------------------------------------------------------------

   An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.25
percent for 2001 decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001, as follows:

                                      1 Percent      1 Percent
                                      Increase        Decrease
------------------------------------------------------------------
                                            (in millions)
Benefit obligation                     $111                $97
Service and interest costs               10                  9
------------------------------------------------------------------

Employee Savings Plan

Southern Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $51
million, $49 million, and $46 million, respectively.

3. CONTINGENCIES AND REGULATORY
   MATTERS

General

Southern Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on Southern Company's financial condition.

Georgia Power Potentially Responsible Party Status

Georgia Power has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act. Georgia


                                       II-31
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Power has recognized $33 million in cumulative expenses through December 31,
2001 for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia, that is listed on the federal National Priorities List.
Georgia Power has contributed to the removal and remedial investigation and
feasibility study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated. As of December 31, 2001, Georgia
Power had recorded approximately $6 million in cumulative expenses associated
with Georgia Power's agreed-upon share of the removal and remedial investigation
and feasibility study costs for the Brunswick site.

   The final outcome of each of these matters cannot now be determined. However,
based on the currently known conditions at these sites and the nature and extent
of Georgia Power's activities relating to these sites, management does not
believe that the company's cumulative liability at these sites would be material
to the financial statements.

Environmental Litigation

On November 3, 1999, the EPA brought a civil action in U.S. District Court in
Georgia against Alabama Power, Georgia Power, and the system service company.
The complaint alleges violations of the New Source Review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in Alabama
and Georgia. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The Clean Air Act authorizes civil penalties
of up to $27,500 per day, per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day.

   The EPA concurrently issued to the operating companies a notice of violation
related to 10 generating facilities, which includes the five facilities
mentioned previously. In early 2000, the EPA filed a motion to amend its
complaint to add the violations alleged in its notice of violation and to add
Gulf Power, Mississippi Power, and Savannah Electric as defendants. The
complaint and notice of violation are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution control equipment when performing maintenance and
construction at coal-burning plants constructed or under construction prior to
1978. The U.S. District Court in Georgia granted Alabama Power's motion to
dismiss for lack of jurisdiction and granted the system service company's motion
to dismiss on the grounds that it neither owned nor operated the generating
units involved in the proceedings. The court granted the EPA's motion to add
Savannah Electric as a defendant, but it denied the motion to add Gulf Power and
Mississippi Power based on lack of jurisdiction over those companies. The court
directed the EPA to refile its amended complaint limiting claims to those
brought against Georgia Power and Savannah Electric. The EPA refiled those
claims as directed by the court. Also, the EPA refiled its claims against
Alabama Power in U.S. District Court in Alabama. It has not refiled against
Gulf Power, Mississippi Power, or the system service company.

   The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.

   Southern Company believes that its operating companies complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. An adverse outcome in any one of these
cases could require substantial capital expenditures that cannot be determined
at this time and could possibly require payment of substantial penalties. This
could affect future results of operations, cash flows, and possibly financial
condition if such costs are not recovered through regulated rates.

Mobile Energy Services' Petition for Bankruptcy

Mobile Energy Services Holdings (MESH), a subsidiary of Southern Company, is the
owner and operator of a facility that generates electricity, produces steam, and
processes black liquor as part of a pulp and paper complex in Mobile, Alabama.
On January 14, 1999, MESH filed a petition for Chapter 11 bankruptcy relief in
the U.S. Bankruptcy Court. This action was in response to Kimberly-Clark Tissue


                                       II-32
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Company's (Kimberly-Clark) announcement in May 1998 of plans to close its pulp
mill, effective September 1, 1999. The pulp mill had historically provided 50
percent of MESH's revenues.

   As a result of settlement discussions with Kimberly-Clark and MESH's
bondholders, Southern Company recorded in 1999 a $69 million after-tax write
down of its investment in MESH. Southern Company recorded an additional $10
million after-tax write down in 2000. At December 31, 2001, MESH had total
assets of $359 million and senior debt outstanding of $190 million of first
mortgage bonds and $72 million related to tax-exempt bonds. In connection with
the bond financings, Southern Company provided certain limited guarantees, in
lieu of funding debt service and maintenance reserve accounts with cash. As of
December 31, 2001, Southern Company had paid the full $41 million pursuant to
the guarantees. Southern Company continues to have guarantees outstanding of
certain potential environmental and other obligations of MESH that represent a
maximum contingent liability of $19 million at December 31, 2001. Mirant has
agreed to indemnify Southern Company for any future obligations incurred under
such guarantees.

   On August 4, 2000, MESH filed a proposed plan of reorganization with the U.S.
Bankruptcy Court. The proposed plan of reorganization was most recently amended
on October 15, 2001. Southern Company expects that approval of a plan of
reorganization would result in either a termination of Southern Company's
ownership interest in MESH or the exchange of all assets of MESH for the
cancellation of securities held by the bondholders but would not affect
Southern Company's continuing guarantee obligations discussed earlier. The final
outcome of this matter cannot now be determined.

California Electricity Markets Litigation

Prior to the spin off of Mirant, Southern Company was named as a defendant in
two lawsuits filed in the superior courts of California alleging that certain
owners of electric generation facilities in California, including Southern
Company, engaged in various unlawful and anticompetitive acts that served to
manipulate wholesale power markets and inflate wholesale electricity prices in
California. One lawsuit naming Southern Company, Mirant, and other generators as
defendants alleged that, as a result of the defendants' conduct, customers paid
approximately $4 billion more for electricity than they otherwise would have and
sought an award of treble damages, as well as other injunctive and equitable
relief. The other suit likewise sought treble damages and equitable relief. The
allegations in the two lawsuits in which Southern Company was named seemed to be
directed to activities of subsidiaries of Mirant. On September 28 and November
6, 2001, the plaintiffs voluntarily dismissed Southern Company without prejudice
from the two lawsuits in which it had been named as a defendant. Prior to being
dismissed, Southern Company had notified Mirant of its claim for indemnification
for costs associated with the lawsuits under the terms of the master separation
agreement that governs the spin off of Mirant. Mirant had undertaken the defense
of the lawsuits. Plaintiffs would not be barred by their own dismissal from
naming Southern Company in some future lawsuit, but management believes that the
likelihood of Southern Company having to pay damages in any such lawsuit is
remote.

Race Discrimination Litigation

On July 28, 2000, a lawsuit alleging race discrimination was filed by three
Georgia Power employees against Georgia Power, Southern Company, and the system
service company in the Superior Court of Fulton County, Georgia. Shortly
thereafter, the lawsuit was removed to the United States District Court for the
Northern District of Georgia. The lawsuit also raised claims on behalf of a
purported class. The plaintiffs seek compensatory and punitive damages in an
unspecified amount, as well as injunctive relief. On August 14, 2000, the
lawsuit was amended to add four more plaintiffs. Also, an additional subsidiary
of Southern Company, Southern Company Energy Solutions, Inc., was named a
defendant.

   On October 11, 2001, the district court denied the plaintiffs' motion for
class certification. The plaintiffs filed a motion to reconsider the order
denying class certification, and the court denied the plaintiffs' motion to
reconsider. On December 28, 2001, the plaintiffs filed a petition in the United
States Court of Appeals for the Eleventh Circuit seeking permission to file an
appeal of the October 11 decision. The defendants filed a brief in opposition of
the petition on January 18, 2002. Discovery of the seven named plaintiffs'
individual claims that remain in the case is ongoing. The final outcome of the
case cannot now be determined.

Alabama Power Rate Adjustment Procedures

In November 1982, the Alabama Public Service Commission (APSC) adopted rates
that provide for periodic adjustments based upon Alabama Power's earned return
on end-of-period retail common equity. The rates also provide for adjustments to
recognize the placing of new generating facilities in retail service. Both
increases and decreases have been placed into effect since the adoption of these
rates. Most recently, a 2 percent increase in retail rates was effective in


                                       II-33
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report

October 2001, in accordance with the Rate Stabilization Equalization plan. The
rate adjustment procedures allow a return on common equity range of 13 percent
to 14.5 percent and limit increases or decreases in rates to 4 percent in any
calendar year and prohibits two consecutive quarterly adjustments in the same
direction.

   In December 1995, the APSC issued an order authorizing Alabama Power to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the company's actual base rate revenues exceed the budgeted revenues. During the
years 2001, 2000, and 1999, Alabama Power did not record any such reductions.

   The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.

Georgia Power Retail Rate Orders

On December 20, 2001, the GPSC approved a three-year retail rate order for
Georgia Power ending December 31, 2004. Under the terms of the order, earnings
will be evaluated against a retail return on common equity range of 10 percent
to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will
be applied to rate refunds, with the remaining one-third retained by Georgia
Power. Retail rates were decreased by $118 million effective January 1, 2002.

   Under a previous three-year order ending December 2001, Georgia Power's
earnings were evaluated against a retail return on common equity range of 10
percent to 12.5 percent. The order further provided for $85 million in each
year, plus up to $50 million of any earnings above the 12.5 percent return
during the second and third years, to be applied to accelerated amortization or
depreciation of assets. Two-thirds of additional earnings above the 12.5 percent
return were applied to rate refunds, with the remaining one-third retained by
Georgia Power. Pursuant to the order, Georgia Power recorded $336 million of
accelerated amortization and interest thereon, which has been credited to a
regulatory liability account as mandated by the GPSC.

   Under the new rate order, the accelerated amortization and the interest will
be amortized equally over three years as a credit to expense beginning in 2002.
Effective January 1, 2002, Georgia Power discontinued recording accelerated
depreciation and amortization. Georgia Power will not file for a general base
rate increase unless its projected retail return on common equity falls below 10
percent. Georgia Power is required to file a general rate case on July 1, 2004,
in response to which the GPSC would be expected to determine whether the rate
order should be continued, modified, or discontinued.

   In 2000 and 1999, Georgia Power recorded $44 million and $79 million,
respectively, of revenue subject to refund for estimated earnings above 12.5
percent retail return on common equity. Refunds applicable to 2000 and 1999 were
made to customers in 2001 and 2000, respectively.

4. JOINT OWNERSHIP AGREEMENTS

Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and
related facilities jointly with Alabama Electric Cooperative, Inc.

   Georgia Power owns undivided interests in plants Vogtle, Hatch, Scherer, and
Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the
Municipal Electric Authority of Georgia, the city of Dalton, Georgia, Florida
Power &Light Company (FP&L), and Jacksonville Electric Authority (JEA). In
addition, Georgia Power has joint ownership agreements with OPC for the Rocky
Mountain facilities and with Florida Power Corporation (FPC) for a combustion
turbine unit at Intercession City, Florida. Southern Power owns an undivided
interest in Stanton Unit A and related facilities jointly with the Orlando
Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power
Agency. The unit is scheduled to go into commercial operation in October 2003.

   At December 31, 2001, Alabama Power's and Georgia Power's ownership and
investment (exclusive of nuclear fuel) in jointly owned facilities with the
above entities were as follows:

                             Jointly Owned Facilities
                       ------------------------------------------
                         Percent     Amount of     Accumulated
                       Ownership    Investment    Depreciation
                       ------------------------------------------
                                         (in millions)
Plant Vogtle
   (nuclear)                45.7%       $3,304          $1,793
Plant Hatch
   (nuclear)                50.1           881             668
Plant Miller
   (coal)
   Units 1 and 2            91.8           747             326
Plant Scherer
   (coal)
   Units 1 and 2             8.4           112              56
Plant Wansley
   (coal)                   53.5           309             152
Rocky Mountain
   (pumped storage)         25.4           169              78
Intercession City
   (combustion turbine)     33.3            12               1
Plant Stanton
   (combined cycle)
   Unit A                   65.0            31               -
-----------------------------------------------------------------

                                       II-34
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


   Alabama Power, Georgia Power, and Southern Power have contracted to operate
and maintain the jointly owned facilities -- except for the Rocky Mountain
project and Intercession City -- as agents for their respective co-owners. The
companies' proportionate share of their plant operating expenses is included in
the corresponding operating expenses in the Consolidated Statements of Income.

5. LONG-TERM POWER SALES AND LEASE
   AGREEMENTS

The operating companies have long-term contractual agreements for the sale and
lease of capacity to certain non-affiliated utilities located outside the
system's service area. These agreements are firm and are related to specific
generating units. Because the energy is generally provided at cost under these
agreements, profitability is primarily affected by capacity revenues.

   Unit power from specific generating plants is currently being sold to FP&L,
FPC, and JEA. Under these agreements, approximately 1,500 megawatts of capacity
is scheduled to be sold annually unless reduced by FP&L, FPC, and JEA for the
periods after 2001 with a minimum of three years notice -- until the expiration
of the contracts in 2010. Capacity revenues from unit power sales amounted to
$170 million in 2001, $177 million in 2000, and $174 million in 1999.

   Southern Power and Mississippi Power have operating leases for portions of
their generating unit capacity. Capacity revenues from these operating leases
amounted to $53 million in 2001 and $20 million in 2000. These amounts are
included in the financial statements as sales for resale. Minimum future
capacity receipts from noncancelable operating leases as of December 31, 2001,
are as follows:

Year                                                  Amounts
----                                              ----------------
                                                   (in millions)
2002                                                     $  64
2003                                                        65
2004                                                        64
2005                                                        23
2006                                                        21
2007 and thereafter                                         97
------------------------------------------------------------------
Total                                                     $334
==================================================================

6. INCOME TAXES

At December 31, 2001, the tax-related regulatory assets and liabilities were
$924 million and $500 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized interest. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits. The following tables and disclosures exclude
discontinued operations.

   Details of income tax provisions are as follows:

                                     2001       2000      1999
-----------------------------------------------------------------
                                           (in millions)
Total provision for income taxes:
Federal --
   Current                           $477       $421      $504
   Deferred                           (10)        95        11
-----------------------------------------------------------------
                                      467        516       515
-----------------------------------------------------------------
State --
   Current                            103         71        85
   Deferred                           (12)         1        (1)
-----------------------------------------------------------------
                                       91         72        84
-----------------------------------------------------------------
Total                                $558       $588      $599
=================================================================

   The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:

                                                2001      2000
---------------------------------------------------------------
                                                 (in millions)
Deferred tax liabilities:
   Accelerated depreciation                   $3,222    $3,199
   Property basis differences                  1,059     1,105
   Other                                         739       650
---------------------------------------------------------------
Total                                          5,020     4,954
---------------------------------------------------------------
Deferred tax assets:
   Federal effect of state deferred taxes        116       111
   Other property basis differences              178       206
   Deferred costs                                234       190
   Pension and other benefits                    123       125
   Other                                         304       231
---------------------------------------------------------------
Total                                            955       863
---------------------------------------------------------------
Total deferred tax liabilities, net            4,065     4,091
Portion included in current assets
   (liabilities), net                             23       (17)
---------------------------------------------------------------
Accumulated deferred income taxes
   in the Consolidated Balance Sheets         $4,088    $4,074
===============================================================

   In accordance with regulatory requirements, deferred investment tax credits
are amortized over the lives of the related property with such amortization
normally applied as a credit to reduce depreciation in the Consolidated
Statements of Income. Credits amortized in this manner amounted to $30 million a
year in 2001, 2000, and 1999. At December 31, 2001, all investment tax credits
available to reduce federal income taxes payable had been utilized.


                                       II-35
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


   The provision for income taxes differs from the amount of income taxes
determined by applying the applicable U.S. Federal statutory rate to earnings
before income taxes and preferred dividends of subsidiaries, as a result of the
following:

                                       2001      2000     1999
----------------------------------------------------------------
Federal statutory rate                 35.0%     35.0%    35.0%
State income tax,
   net of federal deduction             3.7       3.4      3.8
Alternative fuel tax credits           (4.2)     (1.3)    (0.7)
Non-deductible book
   depreciation                         1.7       1.7      1.9
Difference in prior years'
   deferred and current tax rate       (1.1)     (1.3)    (1.3)
Other                                  (2.2)     (0.8)     0.4
----------------------------------------------------------------
Effective income tax rate              32.9%     36.7%    39.1%
================================================================

   Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.

   Mirant was included in the consolidated federal tax return through April 2,
2001. Under the terms of the separation agreement, Mirant will indemnify
Southern Company for subsequent assessment of any additional taxes related to
its transactions prior to the spin off.

7. COMMON STOCK

Stock Issued and Repurchased

Southern Company issued 17 million and 5 million treasury shares of common stock
in 2001 and 2000, respectively, through various company stock plans. Proceeds
were $395 million in 2001 and $140 million in 2000. The shares were issued
through various company stock plans. At December 31, 2001, approximately 2
million treasury shares remain unissued.

   In December 2000, Southern Company issued 28 million treasury shares of
common stock through a public offering. The offering, which included an
overallotment of 3 million shares, raised some $800 million and was priced at
$28.50 per share. The proceeds were used to repay short-term commercial paper.

   In April 1999, Southern Company's Board of Directors approved the repurchase
of up to 50 million shares of Southern Company's common stock over a two-year
period through open market or privately negotiated transactions. Under this
program, 50 million shares were repurchased by February 2000 at an average price
of $25.53 per share.

Shares Reserved

At December 31, 2001, a total of 76 million shares was reserved for issuance
pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside
Directors Stock Plan, and the Omnibus Incentive Compensation Plan (stock option
plan).

Stock Option Plan

Southern Company provides non-qualified stock options to a large segment of its
employees ranging from line management to executives. As of December 31, 2001,
5,622 current and former employees participated in the stock option plan. The
maximum number of shares of common stock that may be issued under this plan may
not exceed 55 million. The prices of options granted to date have been at the
fair market value of the shares on the dates of grant. Options granted to date
become exercisable pro rata over a maximum period of three years from the date
of grant. Options outstanding will expire no later than 10 years after the date
of grant, unless terminated earlier by the Southern Company Board of Directors
in accordance with the plan. Stock option data for the plan has been adjusted to
reflect the Mirant spin off. Activity in 2000 and 2001 for the plan is
summarized below:

                                         Shares        Average
                                        Subject   Option Price
                                      To Option      Per Share
----------------------------------------------------------------
Balance at December 31, 1999         13,419,978         $14.97
Options granted                      11,042,626          14.67
Options canceled                       (335,282)         14.87
Options exercised                    (1,560,695)         13.65
----------------------------------------------------------------
Balance at December 31, 2000         22,566,627          14.92
Options granted                      13,623,210          20.31
Options canceled                     (3,397,152)         15.39
Options exercised                    (3,161,800)         13.83
----------------------------------------------------------------
Balance at December 31, 2001         29,630,885         $17.46
================================================================

Shares reserved for future grants:
  At December 31, 1999               54,684,999
  At December 31, 2000               43,955,368
  At December 31, 2001               64,795,653
---------------------------------------------------------------
Options exercisable:
  At December 31, 2000                9,354,705
  At December 31, 2001               11,965,858
---------------------------------------------------------------

   Southern Company accounts for its stock-based compensation plans in
accordance with Accounting Principles Board Opinion No. 25. Accordingly, no
compensation expense has been recognized.


                                       II-36
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


   The following table summarizes information about options outstanding at
December 31, 2001:

                                           Dollar Price
                                         Range of Options
                                     -------------------------
                                     11-15      15-20    20-24
----------------------------------------------------------------
Outstanding:
   Shares (in thousands)            11,742     12,882    5,007
   Average remaining
      life (in years)                  6.7        7.7      9.1
   Average exercise price           $14.38     $18.34   $22.43
Exerciseable:
   Shares (in thousands)             6,694      5,027      245
   Average exercise price           $14.17     $17.46   $22.42
----------------------------------------------------------------

   The estimated fair values of stock options granted in 2001, 2000, and 1999
were derived using the Black-Scholes stock option pricing model. The following
table shows the assumptions and the weighted average fair values of stock
options:

                                     2001       2000      1999
------------------------------------------------------------------
Interest rate                         4.8%       6.7%      5.8%
Average expected life of
   stock options (in years)           4.3        4.0       3.7
Expected volatility of
   common stock                      25.4%      20.9%     20.7%
Expected annual dividends
   on common stock                  $1.34      $1.34     $1.34
Weighted average fair value
   of stock options granted         $2.82      $3.36     $4.61
------------------------------------------------------------------

   The pro forma impact of fair-value accounting for options granted on earnings
is as follows:


                            Net                      Earnings
Year                       Income                    Per Share
----                  --------------                -------------
                       (in millions)                  (cents)
2001                        $17                        2.4
2000                          8                        1.3
1999                          5                        0.7
-----------------------------------------------------------------

Diluted Earnings Per Share

For Southern Company, the only difference in computing basic and diluted
earnings per share is attributable to outstanding options under the stock option
plan. The effect of the stock options was determined using the treasury stock
method. Shares used to compute diluted earnings per share are as follows:

                                   Average Common Stock Shares
                                --------------------------------
                                2001         2000         1999
----------------------------------------------------------------
                                      (in thousands)
As reported shares           689,352      653,087      685,163
Effect of options              4,191        1,018          530
----------------------------------------------------------------
Diluted shares               693,543      654,105      685,693
================================================================

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 2001, consolidated retained earnings included
$3.4 billion of undistributed retained earnings of the subsidiaries. Of this
amount, $2.1 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures.
However, Georgia Power expects to discharge its first mortgage bond indenture in
early 2002 and to be released from all indenture requirements. The $2.1 billion
restriction includes $1.0 billion for Georgia Power under the current indenture
requirements.

8. FINANCING

Capital and Preferred Securities

Company or subsidiary obligated mandatorily redeemable capital and preferred
securities have been issued by special purpose financing entities of Southern
Company and its subsidiaries. Substantially all the assets of these special
financing entities are junior subordinated notes issued by the related company
seeking financing. Each of these companies considers that the mechanisms and
obligations relating to the capital or preferred securities issued for its
benefit, taken together, constitute a full and unconditional guarantee by it of
the respective special financing entities' payment obligations with respect to
the capital or preferred securities. At December 31, 2001, capital securities of
$950 million and preferred securities of $1.3 billion were outstanding and
recognized in the Consolidated Balance Sheets. Southern Company guarantees the
notes related to $950 million of capital or preferred securities issued on its
behalf.


                                       II-37
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Long-Term Debt Due Within One Year

A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:

                                               2001       2000
-----------------------------------------------------------------
                                                (in millions)
Bond improvement fund requirements             $  5        $11
Less:
   Portion to be satisfied by certifying
      property additions                          1         11
-----------------------------------------------------------------
Cash requirements                                 4          -
First mortgage bond maturities
   and redemptions                                3          -
Other long-term debt maturities                 422         67
-----------------------------------------------------------------
Total                                          $429        $67
=================================================================

   The first mortgage bond improvement fund requirements amount to 1 percent of
each outstanding series of bonds authenticated under the indentures prior to
January 1 of each year, other than those issued to collateralize pollution
control revenue bonds and other obligations. The requirements may be satisfied
by depositing cash or reacquiring bonds, or by pledging additional property
equal to 1662/3 percent of such requirements.

   With respect to the collateralized pollution control revenue bonds, the
operating companies have authenticated and delivered to trustees a like
principal amount of first mortgage bonds as security for obligations under
installment sale or loan agreements. The principal and interest on the first
mortgage bonds will be payable only in the event of default under the
agreements.

   Improvement fund requirements and/or serial maturities through 2006
applicable to total long-term debt are as follows: $429 million in 2002; $1.1
billion in 2003; $894 million in 2004; $399 million in 2005; and $226 million in
2006.

Assets Subject to Lien

Each of Southern Company's subsidiaries is organized as a legal entity, separate
and apart from Southern Company and its other subsidiaries. The subsidiary
companies' mortgages, which secure the first mortgage bonds issued by the
companies, constitute a direct first lien on substantially all of the companies'
respective fixed property and franchises. Georgia Power expects to discharge its
mortgage in early 2002 and that the lien will be removed. There are no
agreements or other arrangements among the subsidiary companies under which the
assets of one company have been pledged or otherwise made available to satisfy
obligations of Southern Company or any of its other subsidiaries.

Bank Credit Arrangements

At the beginning of 2002, unused credit arrangements with banks totaled $5.1
billion, of which $3.7 billion expires during 2002, $500 million expires during
2003, and $900 million expires during 2004. The following table outlines the
credit arrangements by company:

                                   Amount of Credit
                                  ----------------------------
                                                Expires
                                               ---------------
                                                      2003 &
Company                   Total    Unused      2002   beyond
--------------------------------------------------------------
                                     (in millions)
Alabama Power            $  964    $  964    $  574   $  390
Georgia Power             1,765     1,765     1,265      500
Gulf Power                  103       103       103        -
Mississippi Power           115       115       110        5
Savannah Electric            66        66        46       20
Southern Company          1,500     1,500     1,500        -
Southern Power              850       557         -      557
Other                        60        60        60        -
--------------------------------------------------------------
Total                    $5,423    $5,130    $3,658   $1,472
==============================================================

   Approximately $2.9 billion of the credit facilities expiring in 2002 allows
for term loans ranging from one to three years. Most of the agreements include
stated borrowing rates but also allow for competitive bid loans.

   All of the credit arrangements require payment of commitment fees based on
the unused portion of the commitments or the maintenance of compensating
balances with the banks. These balances are not legally restricted from
withdrawal. Included in the $5.1 billion of unused credit arrangements is $4.8
billion of syndicated credit arrangements that require the payment of agent
fees.

   A portion of the $5.1 billion unused credit with banks is allocated to
provide liquidity support to the companies' variable rate pollution control
bonds. The amount of variable rate pollution control bonds requiring liquidity
support as of December 31, 2001 was $1.6 billion.

   Southern Company and the operating companies borrow through commercial paper
programs that have the liquidity support of committed bank credit arrangements.
In addition, the companies from time to time borrow under uncommitted lines of
credit with banks. The amount of commercial paper outstanding at December 31,
2001 was $1.8 billion.


                                       II-38
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


9. COMMITMENTS

Construction Program

Southern Company is engaged in continuous construction programs, currently
estimated to total $2.8 billion in 2002, $2.1 billion in 2003, and $2.3 billion
in 2004. The construction programs are subject to periodic review and revision,
and actual construction costs may vary from the above estimates because of
numerous factors. These factors include: changes in business conditions;
acquisition of additional generating assets; revised load growth estimates;
changes in environmental regulations; changes in existing nuclear plants to meet
new regulatory requirements; increasing costs of labor, equipment, and
materials; and cost of capital. At December 31, 2001, significant purchase
commitments were outstanding in connection with the construction program.
Southern Company has approximately 4,500 megawatts of additional generating
capacity scheduled to be placed in service by 2003, of which 3,900 megawatts
will be competitive generation assets.

   See Management's Discussion and Analysis under "Environmental Matters" for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of the generating plants, Southern
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels, and other financial commitments.
Natural gas purchases are based on various indices at the time of delivery;
therefore, only the volume commitments are firm and disclosed in the following
chart. Also, Southern Company has entered into various long-term commitments for
the purchase of electricity. Total estimated minimum long-term obligations at
December 31, 2001, were as follows:

                           Natural
                             Gas                     Purchased
Year                       MMBtu           Fuel        Power
----                    ------------      ---------------------
                        (in millions)      (in millions)
2002                        163,595    $  2,399       $     97
2003                        188,245       2,185            100
2004                        118,245       1,541             95
2005                         66,390       1,218             95
2006                         49,085       1,155             95
2007 and thereafter          18,120       3,627            879
---------------------------------------------------------------
Total commitments           603,680     $12,125         $1,361
===============================================================

Operating Leases

In May 2001, Mississippi Power began the initial 10-year term of a lease
agreement signed in 1999 for a combined cycle generating facility built at Plant
Daniel. The facility cost approximately $370 million. The lease provides for a
residual value guarantee -- approximately 71 percent of the completion cost --
by Mississippi Power that is due upon termination of the lease in certain
circumstances. The lease also includes purchase and renewal options. Upon
termination of the lease, Mississippi Power may either exercise its purchase
option of the facility or allow it to be sold to a third party. Mississippi
Power expects the fair market value of the leased facility to substantially
reduce or eliminate its payment under the residual value guarantee. The amount
of future minimum operating lease payments exclusive of any payment related to
this guarantee will be approximately $25 million annually during the initial
term.

   Southern Company has other operating lease agreements with various terms and
expiration dates. Total operating lease expenses were $64 million, $42 million,
and $35 million for 2001, 2000, and 1999, respectively. At December 31, 2001,
estimated minimum rental commitments for noncancelable operating leases were as
follows:

Year                                                   Amounts
----                                             --------------
                                                 (in millions)
2002                                                     $  74
2003                                                        71
2004                                                        70
2005                                                        66
2006                                                        58
2007 and thereafter                                        317
---------------------------------------------------------------
Total minimum payments                                    $656
===============================================================

   In addition to the above rental commitments, Alabama Power and Georgia Power
have obligations upon expiration of certain rail car leases with respect to the
residual value of the leased property. These leases expire in 2004, 2006, and
2010, and the maximum obligations are $39 million, $66 million, and $40 million,
respectively. At the termination of the leases, the lessee may either exercise
its purchase option or the property can be sold to a third party. Alabama Power
and Georgia Power expect that the fair market value of the leased property would
substantially reduce or eliminate the payments under the residual value
obligations.


                                       II-39
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


Guarantees

Southern Company has made separate guarantees to certain counterparties
regarding performance of contractual commitments by Mirant's trading and
marketing subsidiaries. At December 31, 2001, the total original notional amount
of guarantees was $53 million, all of which will expire by 2007. Estimated fair
value of these net contractual commitments outstanding was approximately $25
million. Under the terms of the separation agreement, Mirant may not enter into
any new commitments under these guarantees after the spin off date. Based upon a
statistical analysis of credit risk, Southern Company's potential exposure under
these contractual commitments would not materially differ from the estimated
fair value.

   Mirant will pay Southern Company a fee of 1 percent annually on the average
aggregate maximum principal amount of all guarantees outstanding until they are
replaced or expire. Mirant must use reasonable efforts to release Southern
Company from all such support arrangements and will indemnify Southern Company
for any obligations incurred.

10. NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia Power
maintain agreements of indemnity with the NRC that, together with private
insurance, cover third-party liability arising from any nuclear incident
occurring at the companies' nuclear power plants. The act provides funds up to
$9.5 billion for public liability claims that could arise from a single nuclear
incident. Each nuclear plant is insured against this liability to a maximum of
$200 million by American Nuclear Insurers (ANI), with the remaining coverage
provided by a mandatory program of deferred premiums that could be assessed,
after a nuclear incident, against all owners of nuclear reactors. A company
could be assessed up to $88 million per incident for each licensed reactor it
operates, but not more than an aggregate of $10 million per incident to be paid
in a calendar year for each reactor. Such maximum assessment, excluding any
applicable state premium taxes, for Alabama Power and Georgia Power -- based on
its ownership and buyback interests -- is $176 million and $178 million,
respectively, per incident, but not more than an aggregate of $20 million per
company to be paid for each incident in any one year.

   Alabama Power and Georgia Power are members of Nuclear Electric Insurance
Limited (NEIL), a mutual insurer established to provide property damage
insurance in an amount up to $500 million for members' nuclear generating
facilities.

   Additionally, both companies have policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.

   NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years.

   Under each of the NEIL policies, members are subject to assessments if losses
each year exceed the accumulated funds available to the insurer under that
policy. The current maximum annual assessments for Alabama Power and Georgia
Power under the three NEIL policies would be $35 million and $39 million,
respectively.

   Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power plants would be
covered under their insurance. However, both companies revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12-month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.

   For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies shall be
dedicated first for the sole purpose of placing the reactor in a safe and stable
condition after an accident. Any remaining proceeds are to be applied next
toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the company or
to its bond trustees as may be appropriate under the policies and applicable
trust indentures.

   All retrospective assessments -- whether generated for liability, property,
or replacement power -- may be subject to applicable state premium taxes.


                                       II-40
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report


11. DISCOUNTINUED OPERATIONS

In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant and its intentions to spin off the remaining ownership of
Mirant to Southern Company stockholders within 12 months of the initial stock
offering. On October 2, 2000, Mirant completed its initial public offering of
66.7 million shares of common stock priced at $22 per share. This represented
19.7 percent of the 338.7 million shares outstanding. As a result of the stock
offering, Southern Company recorded a $560 million increase in paid-in capital
with no gain or loss being recognized.

   On February 19, 2001, the Southern Company Board of Directors approved the
spin off of its remaining ownership of 272 million Mirant shares. On April 2,
2001, the tax-free distribution of Mirant shares was completed at a ratio of
approximately 0.4 for every share of Southern Company common stock held at
record date.

   The distribution resulted in charges of approximately $3.2 billion and $0.4
billion to Southern Company's paid-in capital and retained earnings,
respectively. The distribution was treated as a non-cash transaction for
purposes of the statement of cash flows.

   As a result of the spin off, Southern Company's financial statements reflect
Mirant's results of operations, balance sheets, and cash flows as discontinued
operations. Certain amounts in the cash flows related to intercompany
eliminations for 2000 and 1999 have been reclassified from cash provided from
operating activities to cash used for discontinued operations.

   Summarized financial information for the discontinued operations is as
follows at December 31:


                                     2001       2000      1999
-----------------------------------------------------------------
                                           (in millions)
Revenues                           $8,182    $13,315    $2,265
Income taxes                           93         86       127
Net income                            142        319       361
-----------------------------------------------------------------

                                                          2000
-----------------------------------------------------------------
                                                 (in millions)
Current assets                                        $  9,057
Total assets                                            22,377
Current liabilities                                      9,726
Total liabilities                                       17,585
Minority and other interests                             1,472
Net assets of
   discontinued operations                               3,320
-----------------------------------------------------------------

12. SEGMENT AND RELATED INFORMATION

Southern Company's reportable business segment is the sale of electricity in the
Southeast by the five operating companies and Southern Power. Net income and
total assets for discontinued operations are included in the reconciling
eliminations column. The all other category includes parent Southern Company,
which does not allocate operating expenses to business segments. Also, this
category includes segments below the quantitative threshold for separate
disclosure. These segments include telecommunications, energy products and
services, and leasing and financing services. Intersegment revenues are not
material. Financial data for business segments and products and services are as
follows:


Business Segments
<TABLE>
<CAPTION>

                                          Electric                    All              Reconciling
Year                                     Utilities                  Other             Eliminations            Consolidated
----                                     -----------------------------------------------------------------------------------
                                                                           (in millions)
2001
-----
<S>                                       <C>                     <C>                     <C>                      <C>
Operating revenues                        $  9,906                $   267                 $    (18)                $10,155
Depreciation and amortization                1,144                     29                        -                   1,173
Interest income                                 21                      8                       (2)                     27
Interest expense                               591                    137                       (2)                    726
Income taxes                                   702                   (144)                       -                     558
Segment net income (loss)                    1,149                    (30)                     143                   1,262
Total assets                                29,389                  2,420                   (1,985)                 29,824
Gross property additions                     2,565                     52                        -                   2,617
----------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       II-41
<PAGE>
NOTES (continued)
Southern Company and Subsidiary Companies 2001 Annual Report
<TABLE>
<CAPTION>

                                          Electric                    All              Reconciling
Year                                     Utilities                  Other             Eliminations            Consolidated
-----                                   ------------------------------------------------------------------------------------
                                                                                   (in millions)
2000
----
<S>                                       <C>                     <C>                     <C>                      <C>
Operating revenues                        $  9,860                $   246                 $    (40)                $10,066
Depreciation and amortization                1,135                     36                        -                   1,171
Interest income                                 21                      7                        1                      29
Interest expense                               615                    197                        -                     812
Income taxes                                   703                   (115)                       -                     588
Segment net income (loss)                    1,109                   (115)                     319                   1,313
Total assets                                26,820                  2,200                    2,240                  31,260
Gross property additions                     2,199                     26                        -                   2,225
----------------------------------------------------------------------------------------------------------------------------

                                          Electric                    All              Reconciling
Year                                     Utilities                  Other             Eliminations            Consolidated
----                                    ------------------------------------------------------------------------------------
                                                                           (in millions)
1999
----
Operating revenues                         $ 9,125                $   221                 $    (29)               $  9,317
Depreciation and amortization                1,046                     93                        -                   1,139
Interest income                                 23                      5                        2                      30
Interest expense                               585                    155                      (38)                    702
Income taxes                                   675                     76                        -                     599
Segment net income (loss)                    1,073                   (158)                     361                   1,276
Total assets                                25,336                  2,127                    1,828                  29,291
Gross property additions                     1,854                     27                        -                   1,881
----------------------------------------------------------------------------------------------------------------------------


Products and Services

                                                         Electric Utilities Revenues
                                    ------------------------------------------------------------------------------------
Year                                Retail            Wholesale                      Other                       Total
----                                ------------------------------------------------------------------------------------
                                                                (in millions)

2001                                $8,440               $1,174                       $292                      $9,906
2000                                 8,600                  977                        283                       9,860
1999                                 8,090                  823                        212                       9,125
------------------------------------------------------------------------------------------------------------------------
</TABLE>

13. QUARTERLY FINANCIAL INFORMATION FOR CONTINUING OPERATIONS (UNAUDITED)

Summarized quarterly financial data for 2001 and 2000 are as follows:
<TABLE>
<CAPTION>

                                                                                              Per Common Share (Note)
                                                                        -----------------------------------------------------
                              Operating    Operating Consolidated          Basic                              Price Range
Quarter Ended                 Revenues       Income   Net Income        Earnings       Dividends          High          Low
--------------               ------------------------------------       -----------------------------------------------------
                                          (in millions)
<S>                           <C>             <C>          <C>           <C>            <C>          <C>           <C>
March 2001                     $2,270          $475         $180          $0.26          $0.335       $21.650       $16.152
June 2001                       2,561           585          270           0.40           0.335        23.880        20.890
September 2001                  3,165           998          554           0.80           0.335        26.000        22.050
December 2001                   2,159           333          116           0.16           0.335        25.980        22.300

March 2000                     $2,052        $  428         $151          $0.23          $0.335       $25.875       $20.375
June 2000                       2,522           598          256           0.39           0.335        27.875        21.688
September 2000                  3,198         1,039          523           0.81           0.335        35.000        23.406
December 2000                   2,294           340           64           0.09           0.335        33.880        27.500
-----------------------------------------------------------------------------------------------------------------------------
Southern Company's business is influenced by seasonal weather conditions.
Note: Market price data in 2001 declined as a result of the Mirant spin off.
</TABLE>


                                       II-42
<PAGE>
<TABLE>
<CAPTION>
Selected Consolidated Financial and Operating Data 1997-2001
Southern Company and Subsidiary Companies 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                                     2001           2000        1999       1998        1997
-----------------------------------------------------------------------------------------------------------------------------

<S>                                                               <C>            <C>          <C>        <C>         <C>
Operating Revenues (in millions)                                  $10,155        $10,066      $9,317     $9,499      $8,774
Total Assets (in millions)                                        $29,824        $31,260     $29,291    $28,723     $27,898
Gross Property Additions (in millions)                             $2,617         $2,225      $1,881     $1,356      $1,138
Return on Average Common Equity (percent)                           13.51          13.20       13.43      10.04       10.30
Cash Dividends Paid Per Share of Common Stock                       $1.34          $1.34       $1.34      $1.34       $1.30
-----------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income (in millions):
   Continuing operations                                           $1,120        $   994     $   915       $986        $990
   Discontinued operations                                            142            319         361         (9)        (18)
-----------------------------------------------------------------------------------------------------------------------------
   Total                                                           $1,262         $1,313      $1,276       $977        $972
=============================================================================================================================
Earnings Per Share From Continuing Operations --
   Basic                                                            $1.62          $1.52       $1.33      $1.41       $1.45
   Diluted                                                           1.61           1.52        1.33       1.41        1.45
Earnings Per Share Including Discontinued Operations --
   Basic                                                            $1.83          $2.01       $1.86      $1.40       $1.42
   Diluted                                                           1.82           2.01        1.86       1.40        1.42
-----------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity                                              $  7,984        $10,690    $  9,204   $  9,797    $  9,647
Preferred stock and securities                                      2,644          2,614       2,615      2,465       2,155
Long-term debt                                                      8,297          7,843       7,251      6,505       6,347
-----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year                       $18,925        $21,147     $19,070    $18,767     $18,149
=============================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                                  42.2           50.6        48.3       52.2        53.2
Preferred stock and securities                                       13.9           12.3        13.7       13.1        11.9
Long-term debt                                                       43.9           37.1        38.0       34.7        34.9
-----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year                         100.0          100.0       100.0      100.0       100.0
=============================================================================================================================
Other Common Stock Data (Note):
Book value per share (year-end)                                    $11.44         $15.69      $13.82     $14.04      $13.91
Market price per share:
   High                                                           $26.000        $35.000     $29.625    $31.563     $26.250
   Low                                                             16.152         20.375      22.063     23.938      19.875
   Close                                                           25.350         33.250      23.500     29.063      25.875
Market-to-book ratio (year-end) (percent)                           221.6          211.9       170.0      207.0       186.0
Price-earnings ratio (year-end) (times)                              15.6           16.5        12.6       20.8        18.2
Dividends paid (in millions)                                         $922           $873        $921       $933        $889
Dividend yield (year-end) (percent)                                   5.3            4.0         5.7        4.6         5.0
Dividend payout ratio (percent)                                      82.4           66.5        72.2       95.6        91.5
Shares outstanding (in thousands):
   Average                                                        689,352        653,087     685,163    696,944     685,033
   Year-end                                                       698,344        681,158     665,796    697,747     693,423
Stockholders of record (year-end)                                 150,242        160,116     174,179    187,053     200,508
-----------------------------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential                                                         3,441          3,398       3,339      3,277       3,220
Commercial                                                            539            527         513        497         479
Industrial                                                             14             14          15         15          16
Other                                                                   4              5           4          5           5
-----------------------------------------------------------------------------------------------------------------------------
Total                                                               3,998          3,944       3,871      3,794       3,720
=============================================================================================================================
Employees (year-end)                                               26,122         26,021      26,269     25,206      24,682
-----------------------------------------------------------------------------------------------------------------------------
Note:  Common stock data in 2001 declined as a result of the Mirant spin off.

</TABLE>


                                       II-43
<PAGE>
<TABLE>
<CAPTION>
Selected Consolidated Financial and Operating Data 1997-2001 (continued)
Southern Company and Subsidiary Companies 2001 Annual Report

------------------------------------------------------------------------------------------------------------------------------------
                                                                     2001           2000        1999       1998        1997
------------------------------------------------------------------------------------------------------------------------------------

Operating Revenues (in millions):
<S>                                                              <C>            <C>           <C>        <C>         <C>
Residential                                                      $  3,247       $  3,361      $3,107     $3,167      $2,836
Commercial                                                          2,966          2,918       2,745      2,766       2,594
Industrial                                                          2,144          2,289       2,238      2,268       2,138
Other                                                                  83             32           -         79          77
------------------------------------------------------------------------------------------------------------------------------------
Total retail                                                        8,440          8,600       8,090      8,280       7,645
Sales for resale within service area                                  338            377         350        374         376
Sales for resale outside service area                                 836            600         473        522         510
------------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity                            9,614          9,577       8,913      9,176       8,531
Other revenues                                                        541            489         404        323         243
------------------------------------------------------------------------------------------------------------------------------------
Total                                                             $10,155        $10,066      $9,317     $9,499      $8,774
====================================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential                                                        44,538         46,213      43,402     43,503      39,217
Commercial                                                         46,939         46,249      43,387     41,737      38,926
Industrial                                                         52,891         56,746      56,210     55,331      54,196
Other                                                                 977            970         945        929         903
------------------------------------------------------------------------------------------------------------------------------------
Total retail                                                      145,345        150,178     143,944    141,500     133,242
Sales for resale within service area                                9,388          9,579       9,440      9,847       9,884
Sales for resale outside service area                              21,380         17,190      12,929     12,988      13,761
------------------------------------------------------------------------------------------------------------------------------------
Total                                                             176,113        176,947     166,313    164,335     156,887
====================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                                          7.29           7.27        7.16       7.28        7.23
Commercial                                                           6.32           6.31        6.33       6.63        6.66
Industrial                                                           4.05           4.03        3.98       4.10        3.95
Total retail                                                         5.81           5.73        5.62       5.85        5.74
Sales for resale                                                     3.82           3.65        3.68       3.92        3.75
Total sales                                                          5.46           5.41        5.36       5.58        5.44
Average Annual Kilowatt-Hour
   Use Per Residential Customer                                    13,014         13,702      13,107     13,379      12,296
Average Annual Revenue Per Residential Customer                   $948.83        $996.44     $938.39    $973.94     $889.29
Plant Nameplate Capacity Owned (year-end) (megawatts)              34,579         32,807      31,425     31,161      31,146
Maximum Peak-Hour Demand (megawatts):
Winter                                                             26,272         26,370      25,203     21,108      22,969
Summer                                                             29,700         31,359      30,578     28,934      27,334
System Reserve Margin (at peak) (percent)                            19.3            8.1         8.5       12.8        15.0
Annual Load Factor (percent)                                         62.0           60.2        59.2       60.0        59.4
Plant Availability (percent):
Fossil-steam                                                         88.1           86.8        83.3       85.2        88.2
Nuclear                                                              90.8           90.5        89.9       87.8        88.8
------------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                                 67.5           72.3        73.1       72.8        74.7
Nuclear                                                              15.2           15.1        15.7       15.4        16.5
Hydro                                                                 2.6            1.5         2.3        3.9         4.3
Oil and gas                                                           8.4            4.0         2.8        3.3         1.7
Purchased power                                                       6.3            7.1         6.1        4.6         2.8
------------------------------------------------------------------------------------------------------------------------------------
Total                                                               100.0          100.0       100.0      100.0       100.0
====================================================================================================================================
</TABLE>
                                                                       II-44

<PAGE>

                              ALABAMA POWER COMPANY
                               FINANCIAL SECTION


                                     II-45

<PAGE>


MANAGEMENT'S REPORT
Alabama Power Company 2001 Annual Report


The management of Alabama Power Company has prepared -- and is responsible for
-- the financial statements and related information included in this report.
These statements were prepared in accordance with accounting principles
generally accepted in the United States and necessarily include amounts that are
based on the best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.

    The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.

    The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.

    The audit committee of the board of directors, composed of four independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.

    Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.

    In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Alabama Power Company in conformity with accounting principles generally
accepted in the United States.


/s/Charles D. McCrary
Charles D. McCrary
President
and Chief Executive Officer


/s/William B. Hutchins, III
William B. Hutchins, III
Executive Vice President,
Chief Financial Officer, and Treasurer

February 13, 2002

                                       II-46


<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Alabama Power Company:


We have audited the accompanying balance sheets and statements of capitalization
of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary
of Southern Company) as of December 31, 2001 and 2000, and the related
statements of income, common stockholder's equity, and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

    We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

    In our opinion, the financial statements (pages II-58 through II-76)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

   As explained in Note 1 to the financial statements, effective January 1,
2001, Alabama Power Company changed its method of accounting for derivative
instruments and hedging activities.





/s/Arthur Andersen LLP
Birmingham, Alabama
February 13, 2002



                                       II-47
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 2001 Annual Report


RESULTS OF OPERATIONS

Earnings

Alabama Power Company's 2001 net income after dividends on preferred stock was
$387 million, representing a $33 million (7.9 percent) decrease from the prior
year. This decline is primarily attributable to a decrease in territorial energy
sales as a result of an economic downturn and milder temperatures.

    In 2000 earnings were $420 million, representing a 5 percent increase from
the prior year. This improvement was primarily attributable to an increase in
territorial sales partially offset by increased non-fuel operating expenses.

    The return on average common equity for 2001 was 11.89 percent compared to
13.58 percent in 2000 and 13.85 percent in 1999.


Revenues

Operating revenues for 2001 were $3.6 billion, reflecting a decrease from 2000.
The following table summarizes the principal factors that have affected
operating revenues for the past two years:

                                           Increase (Decrease)
                              Amount         From Prior Year
                           --------------------------------------
                               2001         2001         2000
-----------------------------------------------------------------
                                         (in thousands)
Retail --
Base revenues              $2,033,814   $ (75,125)    $ 80,264
Fuel cost recovery
   and other                  713,859    (129,909)      61,326
-----------------------------------------------------------------
Total retail                2,747,673    (205,034)     141,590
-----------------------------------------------------------------
Sales for resale --
   Non-affiliates             485,974      24,244       46,353
   Affiliates                 245,189      78,970       73,780
-----------------------------------------------------------------
Total sales for resale        731,163     103,214      120,133
Other operating
   revenues                   107,554      20,749       20,264
-----------------------------------------------------------------
Total operating
   revenues                $3,586,390   $ (81,071)    $281,987
=================================================================
Percent change                             (2.21)%        8.33%
-----------------------------------------------------------------

    Retail revenues of $2.7 billion in 2001 decreased
$205 million (6.9 percent) from the prior year, compared with an increase of
$142 million (5 percent) in 2000. The primary contributors to the decrease in
revenues in 2001 were the negative impact of milder temperatures on energy
sales, an economic downturn in the Company's service territory, and a decrease
in fuel revenues. Fuel revenues have no effect on net income because they
represent the recording of revenues to offset fuel expenses. Fuel rates billed
to customers are designed to fully recover fluctuating fuel costs over a period
of time. Lower natural gas prices, an increased fuel rate, and increased hydro
production combined with decreased costs of purchased power have resulted in a
$154 million (65 percent) reduction in under-recovered fuel costs at December
31, 2001 compared with the prior year. The Company expects to continue to reduce
the balance of $83 million during 2002.


                                      II-48
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


    Other operating revenues in 2001 increased $21 million (23.9 percent) over
2000. This increase is primarily attributed to increased steam sales in
conjunction with the operation of the Company's co-generation facilities, fuel
sales, and rent from electric property. Since co-generation steam revenues are
generally offset by fuel expenses, these revenues did not have a significant
impact on earnings.

    The $20 million (30.5 percent) increase in other operating revenues in 2000
as compared to 1999 was due primarily to an increase in steam sales in
conjunction with the operation of the Company's co-generation facilities.

    Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy energy and
energy sold under short-term contracts are also sold for resale outside the
service area. Revenues from long-term power contracts have both a capacity and
energy component. Capacity revenues reflect the recovery of fixed costs and a
return on investment under the contracts. Energy is generally sold at variable
cost. These capacity and energy components of the unit power contracts were as
follows:

                           2001           2000          1999
                  -------------------------------------------
                                     (in millions)

 Capacity                  $125           $127          $122
 Energy                     134            128           112
 ------------------------------------------------------------
 Total                     $259           $255          $234
 ============================================================

    Capacity revenues from non-affiliates were relatively unchanged in 2001
compared to the prior two years. There are no scheduled declines in capacity
until the termination of the contracts in 2010.

    Revenues from sales to affiliated companies within the Southern electric
system, as well as purchases of energy, will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These transactions did not have a significant impact on earnings.

    Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:

                              KWH            Percent Change
                         ----------------------------------------
                             2001          2001          2000
                         ----------------------------------------
                          (millions)

Residential                  15,881       (5.3)%         6.8%
Commercial                   12,799       (1.5)          5.5
Industrial                   20,460       (7.4)          0.7
Other                           198       (3.9)          2.3
                         ------------
Total retail                 49,338       (5.2)          3.8
Sales for resale -
   Non-affiliates            15,278        2.9          19.4
   Affiliates                 8,843       64.7           6.7
                         ------------
Total                        73,459        1.6           6.9
-----------------------------------------------------------------

    Retail energy sales in 2001 decreased by 5.2 percent due to milder
temperatures and an economic downturn in the Company's service area. This was
offset by an increase in sales for resale to affiliates. Increased operation of
the Company's combined cycle facilities due to lower natural gas prices and an
increase in the Company's combined cycle capacity contributed to the increase in
sales for resale.

    The increase in 2000 retail energy sales was primarily due to the strength
of business and economic conditions in the Company's service area. Residential
energy sales experienced a 6.8 percent increase over the prior year primarily as
a result of warmer summer temperatures and cold winter weather conditions
compared to 1999.

Expenses

In 2001 total operating expenses of $2.7 billion were down $50 million or 1.8
percent compared with 2000. This decline is mainly due to an $18 million net
decrease in fuel and purchased power costs and a $56 million decrease in
non-production operation and maintenance expenses, offset by a $19 million
increase in depreciation. Fuel expenses, including purchased power, are offset
by fuel revenues and have no effect on net income.

    In 2000 total operating expenses of $2.7 billion were up $235 million or 9.4
percent compared with the prior year. This increase was mainly due to a $183
million increase in fuel and purchased power costs, accompanied by a $23 million
increase in maintenance expenses.


                                       II-49
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


    Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net KWH generated were as follows:

                                    --------------------------
                                      2001     2000     1999
                                    --------------------------
Total generation
    (billions of KWHs)                  68       65       63

Sources of generation
    (percent) --
       Coal                             64       72       72
       Nuclear                          18       19       20
       Hydro                             6        3        5
       Oil & Gas                        12        6        3
Average cost of fuel per net
    KWH generated
       (cents) --                     1.56     1.54     1.44
==============================================================

    In 2001, total fuel and purchased power costs of $1.3 billion decreased $18
million (1.4 percent), while total energy sales increased 1,174 million kilowatt
hours (1.6 percent) compared with the amounts recorded in 2000. Fuel and
purchased power costs in 2000 increased $183 million (16 percent) compared to
1999.

    Purchased power consists of purchases from affiliates in the Southern
electric system and non-affiliated companies. Purchased power transactions among
the Company and its affiliates will vary from period to period depending on
demand, the availability, and the variable production cost of generating
resources at each company. During 2001 purchased power transactions from
non-affiliates decreased $20 million (12 percent) due to the addition in May
2001 of a combined cycle unit and an 82 percent increase in hydro generation
compared to the previous year. The hydro generation increase occurred from
greater stream flows in 2001 compared to the previous year.

    The 6 percent decrease in other operation expense in 2001 as compared to
2000 is primarily due to a decrease in administrative and general expenses,
which can be mainly attributed to insurance refunds.

    The 8.5 percent decrease in maintenance expense in 2001 as compared to 2000
is primarily due to a decrease in power production expense as a result of timing
of maintenance for steam power generation facilities. The 8.4 percent increase
in maintenance expense in 2000 as compared to 1999 is primarily attributable to
an increase in the maintenance of overhead distribution lines and additional
accruals to partially replenish the natural disaster reserve.

    Depreciation and amortization expense increased 5.2 percent in 2001 and 4.9
percent in 2000. These increases reflect additions to property, plant, and
equipment.

      Total net interest and other charges increased $10 million (4.0 percent)
in 2001. The increase reflected a decrease in Allowance for Funds Used During
Construction (AFUDC) resulting in a smaller credit to interest expense than was
recorded in 2000. Total net interest and other charges increased $19 million
(7.9 percent) in 2000 primarily from an increase in interest on long-term debt
offset by an increase in AFUDC, which resulted in a larger credit to interest
expense.

Effects of Inflation

The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.

Future Earnings Potential

General

The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of future
earnings depends on numerous factors. The major factor is the ability of the
Company to achieve energy sales growth while containing cost in a more
competitive environment. Growth in energy sales is subject to a number of
factors. These factors include weather, competition, new short- and long-term


                                       II-50
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


contracts with neighboring utilities, energy conservation practiced by
customers, the elasticity of demand, and the rate of economic growth in the
Company's service area.

    Assuming normal weather, sales to retail customers are projected to grow
approximately 2.4 percent annually on average during 2002 through 2006.

    The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
state of Alabama. Prices for electricity provided by the Company to retail
customers are set by the Alabama Public Service Commission (APSC) under
cost-based regulatory principles.

    Rates to retail customers served by the Company are regulated by the APSC.
Rates for the Company can be adjusted periodically within certain limitations
based on earned retail rate of return compared with an allowed return. The rates
also provide for adjustments to recognize the placing of new generating
facilities into retail service under Rate CNP (Certificated New Plant).
Effective July 2001, the Company's retail rates were adjusted by 0.6 percent
under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into
commercial operation on May 1, 2001. Most recently, a 2 percent increase in
retail rates was effective in October 2001, in accordance with the Rate
Stabilization Equalization plan. See Note 3 to the financial statements under
"Retail Rate Adjustment Procedures" for additional information.

    In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items-- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues.

    In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000 the APSC certified a seven-year
purchased power agreement pertaining to 615 megawatts of the wholesale
generating facilities, which were sold to Southern Power in June 2001 and are
under construction in Autaugaville, Alabama. All of the 615 megawatts will be
delivered beginning in 2003. In addition the APSC certified a seven-year
purchased power agreement with a third party for approximately 630 megawatts;
one half of the power will be delivered beginning in 2003 while the remaining
half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail
rates when the contracted capacity delivery begins.

    In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash income of
approximately $57 million in 2001. Future pension income is dependent on several
factors including trust earnings and changes to the plan. For the Company,
pension income is a component of the regulated rates and does not have a
significant effect on net income. For more information see Note 2 to the
financial statements.

    The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.

    Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. The Clean Air Act and other important environmental items are
discussed later under "Environmental Matters."

Industry Restructuring

    The electric utility industry in the United States is continuing to evolve
as a result of regulatory and competitive factors. Among the primary agents of
change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act
allows independent power producers (IPPs) to access a utility's transmission
network in order to sell electricity to other utilities. This enhances the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and/or commercial customers and sell excess energy generation to other
utilities. Also, electricity sales for resale rates are affected by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.

   Although the Energy Act does not permit retail customer access, it was a
major catalyst for the recent restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things
these initiatives allow customers to choose their electricity provider. Some
states have approved initiatives that result in a separation of the ownership
and/or operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While various restructuring and


                                       II-51
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


competition initiatives have been discussed in Alabama, none have been enacted.
In October 2000 the APSC completed a two-year study of electric industry
restructuring, concluding that (i) restructuring of the electric utility
industry in Alabama was not in the public interest and (ii) the APSC itself
would not mandate retail competition or electric industry restructuring without
enabling state legislation. Electric utility restructuring would require
numerous issues to be resolved, including significant ones relating to recovery
of any stranded investments, full cost recovery of energy produced, and other
issues related to the energy crisis that occurred in California. As a result of
that crisis, many states have either discontinued or delayed implementation of
initiatives involving retail deregulation.

   Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the Company does not remain a low-cost producer and provide
quality service, then energy sales growth could be limited, and this could
significantly erode earnings.

   The Company had 1,230 megawatts of wholesale generating facilities under
construction in 2001 at Autaugaville, Alabama. In June 2001 the Company sold
this project to Southern Power Company, a new Southern Company subsidiary formed
in 2001 to construct, own, and manage wholesale generating assets in the
Southeast. The Company has entered into a purchased power agreement with
Southern Power, through May 2010, for half of the capacity of these generating
facilities.

    In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final ruling on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company and its operating companies, including the Company, have
submitted a series of status reports informing the FERC of progress toward the
development of a Southeastern RTO. In these status reports, Southern Company
explained that it is developing a for-profit RTO known as SeTrans with a number
of non-jurisdictional cooperative and public power entities. Recently, Entergy
Corporation and Cleco Power joined the SeTrans development process. In January
2002 the sponsors of SeTrans held a public meeting to form a Stakeholder
Advisory Committee, which will participate in the development of the RTO.
Southern Company continues to work with the other sponsors to develop the
SeTrans RTO. The creation of SeTrans is not expected to have a material impact
on the Company's financial statements. The outcome of this matter cannot now be
determined.

Accounting Standards

Critical Policy

The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operation is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.

New Accounting Standards

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change - effective April 1,
2002 - in accounting for certain contracts related to fuel supplies that contain
quantity options. These contracts will be accounted for as derivatives and
marked to market. However, due to the existence of the Company's cost-based fuel
recovery clause, this change is not expected to have a material impact on net
income.

   In June 2001 the FASB issued Statement No. 142, Goodwill and Other Intangible
Assets, which establishes new accounting and reporting standards for acquired
goodwill and other intangible assets and supersedes Accounting Principles Board
Opinion No. 17. Statement No. 142 addresses how intangible assets that are

                                       II-52
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


acquired individually or with a group of other assets (but not those acquired in
a business combination) should be accounted for upon acquisition and on an
ongoing basis. Goodwill and intangible assets that have indefinite useful lives
will not be amortized but rather will be tested at least annually for
impairment. Intangible assets that have finite useful lives will continue to be
amortized over their useful lives, which are no longer limited to 40 years. The
Company adopted Statement No.142 in January 2002 with no material impact on the
financial statements.

   Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.

FINANCIAL CONDITION

Overview

In 2001, despite significant cost control measures, the Company's earnings were
adversely impacted by an economic downturn and milder temperatures. However,
over the last several years the Company's financial condition has remained
stable as a result of growth in retail energy sales and cost control measures
combined with significant lowering of the cost of capital, achieved through the
refinancing and/or redemption of higher-cost long-term debt and preferred stock.

    The Company had gross property additions of $636 million in 2001. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.

Credit Rating Risk

The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.

Exposure to Market Risk

Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market. Realized gains and losses
are recognized in the income statement as incurred. At December 31, 2001,
exposure from these activities was not material to the Company's financial
position, results of operations, or cash flows. Fair value of changes in energy
trading contracts and year-end valuations are as follows:

                                                   Changes
                                               During the Year
                                             ------------------
                                                 Fair Value
---------------------------------------------------------------
                                               (in thousands)
Contracts beginning of year                       $  567
Contracts realized or settled                       (509)
New contracts at inception                             -
Changes in valuation techniques                        -
Current period changes                               156
---------------------------------------------------------------
Contracts end of year                             $  214
===============================================================

                                       Source of Year-End
                                        Valuation Prices
                              ------------------------------------
                                                   Maturity
                                 Total      ----------------------
                              Fair Value     Year 1     1-3 Years
------------------------------------------------------------------
                                         (in thousands)
------------------------------------------------------------------
Actively quoted               $(4,840)      $(4,801)      $(39)
External sources                5,054         5,054          -
Models and other
   methods                          -             -          -
------------------------------------------------------------------
Contracts end of Year         $   214       $   253       $(39)
==================================================================

    Also, based on the Company's overall variable rate long-term debt exposure
at December 31, 2001, a near-term 100 basis point change in interest rates would
not materially affect the financial statements.

    For additional information, see Note 1 to the financial statements under
"Financial Instruments."

    In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with


                                       II-53
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent of the
budgeted annual amount of natural gas purchases. The Company may not engage in
natural gas hedging activities that extend beyond a rolling 42-month window.


Capital Structure

The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.8 percent in 2001, 42.2 percent in 2000, and 42.4
percent in 1999.

    In August 2001, the Company issued $442 million of senior notes, the
proceeds of which were used to redeem the $131.5 million outstanding principal
of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other
corporate purposes, including the repayment of a portion of its short-term
indebtedness.

Capital Requirements

Capital expenditures are estimated to be $671 million for 2002, $592 million for
2003, and $673 million for 2004. See Note 4 to the financial statements for
additional details.

    Actual construction costs may vary from estimates because of changes in such
factors as: business conditions; environmental regulations; nuclear plant
regulations; load projections; the cost and efficiency of construction labor,
equipment, and materials; and the cost of capital. In addition there can be no
assurance that costs related to capital expenditures will be fully recovered.

Other Capital Requirements

In addition to the funds required for the Company's construction program,
approximately $1.1 billion will be required by the end of 2004 for present
sinking fund requirements and maturities of long-term debt. The Company plans to
continue, when economically feasible, to retire higher cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.

    These capital requirements, lease obligations, and purchase commitments -
discussed in notes 4 and 8 to the financial statements - are as follows:

                                 2002        2003        2004
-----------------------------------------------------------------
                                        (in millions)
Bonds -
    First mortgage            $   4.5     $    -      $    -
    Pollution control             -            -           -
Senior Notes                      -          573.2       525.0
Leases -
    Capital                       0.9          0.9         1.0
    Operating                    27.9         26.5        25.5
Purchase commitments -
    Fuel                        795.0        794.0       801.0
    Purchased Power               -           53.0        83.0
-----------------------------------------------------------------

    At the beginning of 2002, the Company had not used any of its available
credit arrangements. Credit arrangements are as follows:

                                          Expires
                               ----------------------------------
 Total          Unused          2002          2003 & Beyond
-----------------------------------------------------------------
                         (in millions)
 $964             $964          $574            $390
-----------------------------------------------------------------

Environmental Matters

In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company. Reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
were required in two phases. Phase I compliance began in 1995.

    Southern Company achieved Phase I compliance at its affected plants by
primarily switching to low-sulfur coal and with some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $25 million for the Company.

    Phase II sulfur dioxide compliance was required in 2000. The Company used
emission allowances and fuel switching to comply with Phase II requirements.
Also, equipment to control nitrogen oxide emissions was installed on additional
system fossil-fired units as necessary to meet Phase II limits. Compliance with
Phase II increased the Company's total construction expenditures through 2000 by
$63 million.


                                       II-54
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


    In December 2000, the Alabama Department of Environmental Management adopted
revisions to the State Implementation Plan for meeting the one-hour ozone
standard. New emission limits to comply with these requirements must be
implemented in May 2003. Two generating plants will be affected in the
Birmingham area. Capital expenditures for compliance with these new rules are
currently estimated at approximately $240 million, of which $170 million remains
to be spent.

    In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
made the standards significantly more stringent. In the subsequent litigation of
these standards, the U. S. Supreme Court found the EPA's implementation program
for the new ozone standard unlawful and remanded it to the EPA. In addition, the
Federal District of Columbia Circuit Court of Appeals is considering other legal
challenges to these standards. A court decision is expected in the spring of
2002. If the standards are eventually upheld, implementation could be required
by 2007 to 2010.

    In September 1998, the EPA issued nitrogen oxide reduction rules to the
states for implementation. The final rule affects 21 states, including Alabama.
Compliance is required by May 31, 2004 for most states including Alabama.
Capital expenditures for compliance with these new rules are currently estimated
at approximately $175 million.

    A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.

    On November 3, 1999, the EPA brought a civil action against the Company in
the U.S. District Court in Atlanta, Georgia. The complaint alleges violations of
the New Source Review provisions of the Clean Air Act with respect to coal-fired
generating facilities at the Company's Plants Miller, Barry, and Gorgas. The
civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The EPA concurrently issued to the Company a notice of violation
relating to these specific facilities, as well as Plants Greene County and
Gaston. In early 2000 the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation. The complaint and notice of
violation are similar to those brought against and issued to several other
electric utilities. The complaint and notice of violation allege that the
Company had failed to secure necessary permits or install additional pollution
control equipment when performing maintenance and construction at coal burning
plants constructed or under construction prior to 1978. In August 2000, the U.S.
District Court in Georgia granted the Company's motion to dismiss for lack of
jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims
against the Company in federal district court in Birmingham, Alabama. The case
has been stayed since the spring of 2001, pending a ruling by the U.S. Court of
Appeals for the Eleventh Circuit in the appeal of a very similar New Source
Review enforcement action against the Tennessee Valley Authority (TVA). The TVA
case involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on the Company, it is party to that case as well. The U.S. District Court
in Alabama has indicated that it will revisit the issue of a continued stay in
April 2002.

     The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. However, an adverse outcome in this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. The Clean Air Act authorizes civil penalties
of up to $27,500 per day per violation at each generating unit. Prior to January
30, 1997, the penalty was $25,000 per day. This could affect future results of
operations, cash flows, and possibly financial condition unless such costs can
be recovered through regulated rates.

    In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury, and perhaps other HAPS is warranted. The program is
being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and the regulations are scheduled to be finalized by the end
of 2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional


                                       II-55
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.

    Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.

   In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.

   The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.

    The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup and
will recognize in the financial statements costs to clean up known sites. The
Company has not incurred any significant cleanup costs to date.

   Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.

   Compliance with possible additional legislation related to global climate
change, and other environmental and health concerns could significantly affect
the Company. The impact of new legislation -- if any -- will depend on the
subsequent development and implementation of applicable regulations.

Sources of Capital

The Company plans to obtain the funds required for construction and other
purposes from sources similar to those used in the past, which were primarily
from internal sources. However, the type and timing of any financings - if
needed - will depend on market conditions and regulatory approval. In recent
years financings primarily have utilized unsecured debt and trust preferred
securities.

    The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $10 million of commercial
paper.

    As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the Company has established external trust funds for nuclear decommissioning
costs. In 1994 the Company also established an external trust fund for
postretirement benefits as ordered by the APSC. The cumulative effect of funding
these items over a long period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."

Cautionary Statement Regarding Forward-Looking
Information

This Annual Report includes forward-looking statements in addition to historical
information. Forward-looking information includes, among other things,
statements concerning projected retail sales growth and scheduled completion of
new generation. In some cases forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"


                                       II-56
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2001 Annual Report


"anticipates," "believes," "estimates," "predicts," "projects," "potential,"
"continue," or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action against the Company; the impact of fluctuations in commodity prices,
interest rates, and customer demand; state and federal rate regulations;
political, legal, and economic conditions and developments in the United States;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets
or businesses, which cannot be assured to be completed or beneficial to the
Company; the effects of and changes in economic conditions in the areas in which
the Company operates; the direct or indirect effects on the Company's business
resulting from the terrorist incidents on September 11, 2001, or any similar
such incidents or responses to such incidents; financial market conditions and
the results of financing efforts; the timing and acceptance of the Company's new
product and service offerings; the ability of the Company to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports (including
Form 10-K) filed from time to time by the Company with the Securities and
Exchange Commission.



                                       II-57


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report

---------------------------------------------------------------------------------------------------------------------
                                                                         2001                2000               1999
---------------------------------------------------------------------------------------------------------------------
                                                                                  (in thousands)
Operating Revenues:
<S>                                                                <C>                 <C>                <C>
Retail sales                                                       $2,747,673          $2,952,707         $2,811,117
Sales for resale --
  Non-affiliates                                                      485,974             461,730            415,377
  Affiliates                                                          245,189             166,219             92,439
Other revenues                                                        107,554              86,805             66,541
---------------------------------------------------------------------------------------------------------------------
Total operating revenues                                            3,586,390           3,667,461          3,385,474
---------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                              1,000,828             963,275            855,632
  Purchased power --
   Non-affiliates                                                     144,991             164,881             93,204
   Affiliates                                                         147,967             184,014            180,563
  Other                                                               508,264             538,529            531,696
Maintenance                                                           275,510             301,046            277,724
Depreciation and amortization                                         383,473             364,618            347,574
Taxes other than income taxes                                         214,665             209,673            204,645
---------------------------------------------------------------------------------------------------------------------
Total operating expenses                                            2,675,698           2,726,036          2,491,038
---------------------------------------------------------------------------------------------------------------------
Operating Income                                                      910,692             941,425            894,436
Other Income (Expense):
Interest income, net                                                   15,101              16,152             15,671
Equity in earnings of unconsolidated subsidiaries (Note 5)              4,494               3,156              2,650
Other, net                                                             (8,579)             (2,226)           (12,805)
---------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                             921,708             958,507            899,952
---------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net                                                 246,436             235,331            217,066
Distributions on preferred securities of subsidiary (Note 8)           24,775              25,549             24,662
---------------------------------------------------------------------------------------------------------------------
Total interest and other, net                                         271,211             260,880            241,728
---------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                          650,497             697,627            658,224
Income taxes (Note 7)                                                 248,597             261,555            241,880
---------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of                                  401,900             436,072            416,344
   Accounting Change
Cumulative effect of accounting change
   less income taxes of $215 thousand                                     353                   -                  -
---------------------------------------------------------------------------------------------------------------------
Net Income                                                            402,253             436,072            416,344
Dividends on Preferred Stock                                           15,524              16,156             16,464
---------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock                      $  386,729          $  419,916         $  399,880
=====================================================================================================================
The accompanying notes are an integral part of these statements.


</TABLE>





                                                               II-58




<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report

----------------------------------------------------------------------------------------------------------------------------
                                                                              2001                 2000                1999
----------------------------------------------------------------------------------------------------------------------------
                                                                                        (in thousands)
Operating Activities:
<S>                                                                      <C>                  <C>                 <C>
Net income                                                               $ 402,253            $ 436,072           $ 416,344
Adjustments to reconcile net income
 to net cash provided from operating activities --
     Depreciation and amortization                                         437,490              412,998             403,332
     Deferred income taxes and investment tax credits, net                 (21,569)              66,166              29,039
     Other, net                                                           (122,651)             (37,703)            (12,661)
     Changes in certain current assets and liabilities --
       Receivables, net                                                     88,325             (125,652)             33,509
       Fossil fuel stock                                                   (38,663)              23,967              (1,344)
       Materials and supplies                                              (13,025)             (10,662)            (17,968)
       Accounts payable                                                    (83,077)             107,702             (38,556)
       Energy cost recovery, retail                                        154,320              (69,190)            (97,869)
       Other                                                                34,503               23,336               5,930
----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                                837,906              827,034             719,756
----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                                  (635,540)            (870,581)           (809,044)
Sales of property                                                          102,068                    -                   -
Other                                                                      (34,771)             (49,414)            (72,218)
----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                    (568,243)            (919,995)           (881,262)
----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                 (271,347)             184,519              96,824
Proceeds --
    Common stock                                                            15,642                    -                   -
    Other long-term debt                                                   477,000              250,000             751,650
    Preferred securities                                                         -                    -              50,000
    Capital contributions from parent company                              107,313              204,371             204,347
Redemptions --
    First mortgage bonds                                                  (138,991)            (111,009)           (470,000)
    Other long-term debt                                                   (19,021)              (5,987)           (104,836)
    Preferred stock                                                              -                    -             (50,000)
Payment of preferred stock dividends                                       (14,942)             (16,110)            (15,788)
Payment of common stock dividends                                         (393,900)            (417,100)           (399,600)
Other                                                                       (9,908)                (951)            (15,864)
----------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities                    (248,154)              87,733              46,733
----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                     21,509               (5,228)           (114,773)
Cash and Cash Equivalents at Beginning of Period                            14,247               19,475             134,248
----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                                $ 35,756             $ 14,247            $ 19,475
============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
    Interest (net of amount capitalized)                                  $246,316             $237,066            $229,305
    Income taxes (net of refunds)                                          223,961              175,303             170,121
------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.

</TABLE>


                                                              II-59


<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report

-------------------------------------------------------------------------------------------------------------------
Assets                                                                               2001                     2000
-------------------------------------------------------------------------------------------------------------------
                                                                                            (in thousands)
Current Assets:
<S>                                                                              <C>                      <C>
Cash and cash equivalents                                                     $    35,756              $    14,247
Receivables --
  Customer accounts receivable                                                    281,985                  337,870
  Under-recovered retail fuel clause revenue                                       83,497                  237,817
  Other accounts and notes receivable                                              49,940                   60,315
  Affiliated companies                                                             72,639                   95,704
  Accumulated provision for uncollectible accounts                                 (5,237)                  (6,237)
Refundable income taxes                                                                 -                        -
Fossil fuel stock, at average cost                                                 99,278                   60,615
Materials and supplies, at average cost                                           191,324                  178,299
Other                                                                              74,640                   52,624
-------------------------------------------------------------------------------------------------------------------
Total current assets                                                              883,822                1,031,254
-------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service                                                                     13,159,560               12,431,575
Less accumulated provision for depreciation                                     5,309,557                5,107,822
-------------------------------------------------------------------------------------------------------------------
                                                                                7,850,003                7,323,753
Nuclear fuel, at amortized cost                                                    88,777                   94,050
Construction work in progress                                                     357,906                  744,974
-------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                            8,296,686                8,162,777
-------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 5)                         44,742                   38,623
Nuclear decommissioning trusts                                                    317,508                  313,895
Other                                                                              12,244                   13,612
-------------------------------------------------------------------------------------------------------------------
Total other property and investments                                              374,494                  366,130
-------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 7)                                 334,830                  345,550
Prepaid pension costs                                                             314,100                  255,256
Debt expense, being amortized                                                       8,150                    8,758
Premium on reacquired debt, being amortized                                        77,173                   76,020
Department of Energy assessments                                                   21,015                   24,588
Other                                                                             108,031                   95,772
-------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                           863,299                  805,944
-------------------------------------------------------------------------------------------------------------------
Total Assets                                                                  $10,418,301              $10,366,105
===================================================================================================================
The accompanying notes are an integral part of these balance sheets.


</TABLE>



                                                              II-60
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report

--------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                                        2001                     2000
--------------------------------------------------------------------------------------------------------------------------
                                                                                                   (in thousands)
Current Liabilities:
<S>                                                                                <C>                      <C>
Securities due within one year (Note 8)                                              $     5,382              $       844
Notes payable                                                                              9,996                  281,343
Accounts payable --
  Affiliated                                                                              98,268                  124,534
  Other                                                                                  151,705                  209,205
Customer deposits                                                                         42,124                   36,814
Taxes accrued --
  Income taxes                                                                           113,003                   65,505
  Other                                                                                   19,023                   19,471
Interest accrued                                                                          35,522                   33,186
Vacation pay accrued                                                                      32,324                   31,711
Other                                                                                     93,589                   97,743
--------------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                                600,936                  900,356
--------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                           3,742,346                3,425,527
--------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7)                                             1,387,661                1,401,424
Deferred credits related to income taxes (Note 7)                                        202,881                  222,485
Accumulated deferred investment tax credits                                              238,225                  249,280
Employee benefits provisions                                                              99,919                   71,813
Prepaid capacity revenues (Note 6)                                                        40,730                   58,377
Other                                                                                    130,214                  176,559
--------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                           2,099,630                2,179,938
--------------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
  securities of subsidiary trusts holding company junior
  subordinated notes (See accompanying statements) (Note 8)                              347,000                  347,000
--------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements)                                 317,512                  317,512
--------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                              3,310,877                3,195,772
--------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                           $10,418,301              $10,366,105
==========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>




                                                                II-61


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report

----------------------------------------------------------------------------------------------------------------------------------
                                                                           2001             2000            2001             2000
----------------------------------------------------------------------------------------------------------------------------------
                                                                                (in thousands)              (percent of total)
Long-Term Debt:
First mortgage bonds --
       Maturity                           Interest Rates
       --------                           --------------
       <S>                               <C>                           <C>             <C>              <C>              <C>
       2023 through 2024                  7.30% - 7.75%                $350,000         $488,991
----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                              350,000          488,991
----------------------------------------------------------------------------------------------------------------------------------
Senior notes --
       Variable rate (2.28% at 1/1/02)
          due March 3, 2003                                             167,000                -
       5.35% due November 15, 2003                                      156,200          156,200
       7.850% due May 15, 2003                                          250,000          250,000
       7.125% due August 15, 2004                                       250,000          250,000
       4.875% due September 1, 2004                                     275,000                -
       5.49% due November 1, 2005                                       225,000          225,000
       7.125% due October 1, 2007                                       200,000          200,000
       5.375% due October 1, 2008                                       160,000          160,000
       6.25% to 7.125% due 2010-2048                                  1,199,402        1,202,581
----------------------------------------------------------------------------------------------------------------------------------
Total senior notes                                                    2,882,602        2,443,781
----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
     Pollution control revenue bonds --
       Collateralized:
         5.50% due 2024                                                  24,400           24,400
         Variable rates (1.61% to 1.95% at 1/1/02)
          due 2015-2017                                                  89,800           89,800
       Non-collateralized:
         6.69% due 2021                                                  50,000           65,000
         Variable rates (1.75% to 2.05% at 1/1/02)
          due 2021-2031                                                 395,940          360,940
----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt (Note 8)                                     560,140          540,140
----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations                                             3,323            4,165
----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net                                (48,337)         (50,706)
----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
  requirement -- $217.2 million)                                      3,747,728        3,426,371
Less amount due within one year                                           5,382              844
----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year                  $3,742,346       $3,425,527           48.5%            46.9%
----------------------------------------------------------------------------------------------------------------------------------

</TABLE>



                                                              II-62



<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Alabama Power Company 2001 Annual Report

--------------------------------------------------------------------------------------------------------------------------
                                                                   2001             2000            2001             2000
--------------------------------------------------------------------------------------------------------------------------
                                                                         (in thousands)             (percent of total)
Company Obligated Mandatorily
  Redeemable Preferred Securities:  (Note 8)
$25 liquidation value --
<S>                                                            <C>               <C>                <C>               <C>
  7.375%                                                     $   97,000       $   97,000
  7.60%                                                         200,000          200,000
  Auction rate (3.60% at 1/1/02)                                 50,000           50,000
--------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $24.2 million)        347,000          347,000             4.5              4.8
--------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par or stated value --
  4.20% to 4.92%                                                 47,512           47,512
$25 par or stated value --
  5.20% to 5.83%                                                200,000          200,000
Auction rates -- at 1/1/02
  3.10% to 3.557%                                                70,000           70,000
--------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $15.2 million)            317,512          317,512             4.1              4.4
--------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
  Authorized  - 6,000,000 shares
  Outstanding - 6,000,000 shares in 2001
    and 5,608,955 shares in 2000
  Par value                                                     240,000          224,358
  Paid-in capital                                             1,850,676        1,743,363
  Premium on Preferred Stock                                         99               99
Retained earnings                                             1,220,102        1,227,952
--------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                             3,310,877        3,195,772            42.9             43.9
--------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                         $7,717,735       $7,285,811          100.0%           100.0%
==========================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>




                                                              II-63
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Alabama Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                                                Premium on
                                                   Common         Paid-In        Preferred     Retained
                                                    Stock         Capital         Stock        Earnings          Total
-----------------------------------------------------------------------------------------------------------------------------
                                                                               (in thousands)

<S>                                                 <C>           <C>                  <C>      <C>              <C>
Balance at January 1, 1999                           $224,358      $1,334,645           $99      $1,224,965       $2,784,067
Net income after dividends on preferred stock               -               -             -         399,880          399,880
Capital contributions from parent company                   -         204,347             -               -          204,347
Cash dividends on common stock                              -               -             -        (399,600)        (399,600)
Other                                                       -               -             -             169              169
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                          224,358       1,538,992            99       1,225,414        2,988,863
Net income after dividends on preferred stock               -               -             -         419,916          419,916
Capital contributions from parent company                   -         204,371             -               -          204,371
Cash dividends on common stock                              -               -             -        (417,100)        (417,100)
Other                                                       -               -             -            (278)            (278)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000                          224,358       1,743,363            99       1,227,952        3,195,772
Net income after dividends on preferred stock               -               -             -         386,729          386,729
Capital contributions from parent company                   -         107,313             -               -          107,313
Cash dividends on common stock                              -               -             -        (393,900)        (393,900)
Issuance of common stock                               15,642               -             -               -           15,642
Other                                                       -               -             -            (679)            (679)
----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001                         $240,000      $1,850,676           $99      $1,220,102       $3,310,877
=============================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>


                                                              II-64


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2001 Annual Report


1.   SUMMARY OF SIGNIFICANT ACCOUNTING
     POLICIES

General

Alabama Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern LINC), Southern
Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern
Power), and other direct and indirect subsidiaries. The operating companies --
Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi
Power Company, and Savannah Electric and Power Company -- provide electric
service in four southeastern states. Contracts among the operating companies -
related to jointly-owned generating facilities, interconnecting transmission
lines, and the exchange of electric power -- are regulated by the Federal Energy
Regulatory Commission (FERC) and/or the Securities and Exchange Commission
(SEC). The system service company provides, at cost, specialized services to
Southern Company and its subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Power was
established in 2001 to construct, own, and manage Southern Company's competitive
generation assets and sell electricity at market-based rates in the wholesale
market.

    Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The Company follows accounting principles generally accepted in the
United States and complies with the accounting policies and practices prescribed
by its respective regulatory commissions. The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States requires the use of estimates, and the actual results may differ
from those estimates.

   Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.

Affiliate Transactions

The Company has an agreement with the system service company under which the
following services are rendered to the Company at cost: general and design
engineering, purchasing, accounting and statistical, finance and treasury, tax,
information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures, and other services with
respect to business and operations and power pool transactions. Costs for these
services amounted to $183 million, $187 million, and $218 million during 2001,
2000, and 1999, respectively.

   The Company also has an agreement with Southern Nuclear to operate Plant
Farley and provide the following nuclear-related services at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting,
statistical, and employee relations; and other services with respect to business
and operations. Costs for these services amounted to $160 million, $148 million,
and $135 million during 2001, 2000, and 1999, respectively.

   In 2001, the Company had under construction a 1,230 megawatt combined cycle
facility in Autaugaville, Alabama. In June 2001, the Company sold this project
to Southern Power Company, a new Southern Company affiliate formed in 2001 to
construct, own, and manage wholesale generating assets in the Southeast.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues associated with
certain costs that are expected to be recovered from customers through the
ratemaking process. Regulatory liabilities represent probable future reductions
in revenues associated with amounts that are expected to be credited to
customers through the ratemaking process.


                                     II-65
<PAGE>

NOTES (continued)
Alabama Power Company 2001 Annual Report


   Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:

                                             2001        2000
                                         -----------------------
                                              (in millions)
Deferred income tax charges                $  335      $  346
Deferred income tax credits                  (203)       (222)
Premium on reacquired debt                     77          76
Department of Energy assessments               21          25
Vacation pay                                   32          32
Natural disaster reserve                      (12)        (18)
Other, net                                     57          30
----------------------------------------------------------------
Total                                      $  307      $  269
================================================================

    In the event that a portion of the Company's operations is no longer subject
to the provisions of FASB Statement No. 71, the Company would be required to
write off related regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair values.

Revenues and Fuel Costs

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Alabama and to wholesale customers in the southeast.
Revenues are recognized as services are rendered. Unbilled revenues are accrued
at the end of each fiscal period. Fuel revenues have no effect on net income
because they represent the recording of revenues to offset fuel expenses,
including the fuel component of purchased energy. Fuel rates billed to customers
are designed to fully recover fluctuating fuel costs over a period of time.

    The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts continue to average less than 1 percent of revenues.

    Fuel expense includes the amortization of the cost of nuclear fuel and a
charge based on nuclear generation for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $58
million in 2001, $61 million in 2000, and $63 million in 1999.

    The Company has a contract with the U.S. Department of Energy (DOE) that
provides for the permanent disposal of spent nuclear fuel. The DOE failed to
begin disposing of spent fuel in January 1998 as required by the contract, and
the Company is pursuing legal remedies against the government for breach of
contract. Sufficient fuel storage capacity is available at Plant Farley to
maintain full-core discharge capability until the refueling outage scheduled in
2006 for Farley Unit 1 and the refueling outage scheduled in 2008 for Farley
Unit 2. Procurement of on-site dry spent fuel storage capacity at Plant Farley
is in progress, with the intent to place the capacity in operation as early as
2005.

    Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is funded in part by
a special assessment on utilities with nuclear plants. This assessment is being
paid over a 15-year period, which began in 1993. This fund will be used by the
DOE for the decontamination and decommissioning of its nuclear fuel enrichment
facilities. The law provides that utilities will recover these payments in the
same manner as any other fuel expense. The Company estimates its remaining
liability under this law to be approximately $21 million at December 31, 2001.
This obligation is recognized in the accompanying Balance Sheets.

Depreciation and Nuclear Decommissioning

Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.2 percent in 2001, 2000, and 1999. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to accumulated
provision for depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
Depreciation expense includes an amount for the expected cost of decommissioning
nuclear facilities and removal of other facilities.

    The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial nuclear power reactors to establish a plan for providing with
reasonable assurance funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Amounts previously
recorded in internal reserves are being transferred into the external trust
funds over periods approved by the APSC. The NRC's minimum external funding
requirements are based on a generic estimate of the cost to decommission the
radioactive portions of a nuclear unit based on the size and type of reactor.


                                      II-66
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


The Company has filed plans with the NRC to ensure that -- over time -- the
deposits and earnings of the external trust funds will provide the minimum
funding amounts prescribed by the NRC.

    Site study cost is the estimate to decommission the facility as of the site
study year, and ultimate cost is the estimate to decommission the facility as of
retirement date. The estimated costs of decommissioning -- both site study costs
and ultimate costs - based on the most current study for Plant Farley were as
follows:


  Site study basis (year)                           1998

  Decommissioning periods:
      Beginning year                                2017
      Completion year                               2031
  ------------------------------------------------------------
                                                (in millions)
  Site study costs:
      Radiated structures                           $629
      Non-radiated structures                         60
  ------------------------------------------------------------
  Total                                             $689
  ============================================================
                                                (in millions)
  Ultimate costs:
      Radiated structures                         $1,868
      Non-radiated structures                        178
  ------------------------------------------------------------
  Total                                           $2,046
  ============================================================

    The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.

    Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the APSC. The amount expensed in 2001 and fund balances as of
December 31, 2001 were:

                                                 (in millions)
  Amount expensed in 2001                            $ 18
  -------------------------------------------------------------

  Accumulated provisions:
      External trust funds, at fair value            $318
      Internal reserves                                36
  -------------------------------------------------------------
  Total                                              $354
  =============================================================

    All of the Company's decommissioning costs are approved for recovery by the
APSC through the ratemaking process. Significant assumptions include an
estimated inflation rate of 4.5 percent and an estimated trust earnings rate of
7.0 percent. The Company expects the APSC to periodically review and adjust, if
necessary, the amounts collected in rates for the anticipated cost of
decommissioning.

Income Taxes

The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.

Allowance For Funds Used During Construction
(AFUDC)

AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The amount of AFUDC capitalized was $19 million in 2001,
$43 million in 2000, and $23 million in 1999. The composite rate used to
determine the amount of allowance was 7.7 percent in 2001, 9.6 percent in 2000,
and 8.8 percent in 1999. AFUDC, net of income tax, as a percent of net income
after dividends on preferred stock was 3.3 percent in 2001, 8.4 percent in 2000,
and 4.7 percent in 1999.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction. The cost of
maintenance, repairs and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property--exclusive of minor
items of property--is capitalized.

Financial Instruments

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended.  The impact on
net income was immaterial.

    The Company uses derivative financial instruments to hedge exposures to
fluctuations in foreign currency exchange rates and certain commodity prices.


                                       II-67
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


Gains and losses on qualifying hedges are deferred and recognized either in
income or as an adjustment to the carrying amount of the hedged item when the
transaction occurs.

    The Company and its affiliates, through the system service company acting as
their agent, enters into commodity related forward and option contracts to limit
exposure to changing prices on certain fuel purchases and electricity purchases
and sales. Substantially all of the Company's bulk energy purchases and sales
contracts meet the definition of a derivative under FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities. In many cases
these fuel and electricity contracts qualify for normal purchase and sale
exceptions under Statement No. 133 and are accounted for under the accrual
method. Other contracts qualify as cash flow hedges of anticipated transactions,
resulting in the deferral of related gains and losses and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.

    In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent of the
budgeted annual amount of natural gas purchases. The Company may not engage in
natural gas hedging activities that extend beyond a rolling 42-month window.

    The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.

    Other Company financial instruments for which the carrying amount did not
equal fair value at December 31 are as follows:

                                        Carrying        Fair
                                         Amount         Value
                                      -------------------------
                                            (in millions)

 Long-term debt:
   At December 31, 2001                  $3,744        $3,800
   At December 31, 2000                   3,422         3,375
 Preferred Securities:
   At December 31, 2001                     347           346
   At December 31, 2000                     347           344
 --------------------------------------------------------------

   The fair value for long-term debt and preferred securities was based on
either closing market prices or closing prices of comparable instruments.

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.

Materials and Supplies

Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.

Natural Disaster Reserve

In accordance with an APSC order, the Company has established a Natural Disaster
Reserve. The Company is allowed to accrue $250 thousand per month until the
maximum accumulated provision of $32 million is attained. Higher accruals to
restore the reserve to its authorized level are allowed whenever the balance in
the reserve declines below $22.4 million. At December 31, 2001, the reserve
balance was $12 million.

2.   RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all employees may become
eligible for such benefits when they retire. The Company funds trusts to the
extent deductible under federal income tax regulations or to the extent required
by the APSC and the FERC. In late 2000 the Company adopted several pension and
postretirement benefit plan changes that had the effect of increasing benefits
to both current and future retirees.


                                       II-68
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


    The measurement date for plan assets and obligations is September 30 of each
year. The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:

                                          2001         2000
-------------------------------------------------------------
Discount                                  7.50%        7.50%
Annual salary increase                    5.00         5.00
Long-term return on plan assets           8.50         8.50
-------------------------------------------------------------

Pension Plan

Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
                                             Projected
                                        Benefit Obligations
                                    ------------------------
                                         2001          2000
------------------------------------------------------------
                                           (in millions)
Balance at beginning of year             $925          $896
Service cost                               25            23
Interest cost                              70            65
Benefits paid                             (56)          (51)
Actuarial gain and
    employee transfers                     (1)           (8)
Amendments                                 48             -
------------------------------------------------------------
Balance at end of year                 $1,011          $925
============================================================

                                            Plan Assets
                                    ------------------------
                                         2001          2000
------------------------------------------------------------
                                           (in millions)
Balance at beginning of year           $1,921        $1,647
Actual return on plan assets             (277)          302
Benefits paid                             (56)          (51)
Employee transfers                         (4)           23
------------------------------------------------------------
Balance at end of year                 $1,584        $1,921
============================================================

      The accrued pension costs recognized in the Balance Sheets were as
follows:

                                               2001      2000
---------------------------------------------------------------
                                               (in millions)
Funded status                                 $ 573     $ 996
Unrecognized transition obligation              (15)      (20)
Unrecognized prior service cost                  78        36
Unrecognized net actuarial gain                (322)     (757)
---------------------------------------------------------------
Prepaid asset recognized in the
    Balance Sheets                            $ 314     $ 255
===============================================================

    Components of the pension plan's net periodic cost were as follows:

                                        2001    2000     1999
---------------------------------------------------------------
                                            (in millions)
Service cost                           $  25   $  23    $  23
Interest cost                             70      65       58
Expected return on plan assets          (131)   (119)    (109)
Recognized net actuarial gain            (22)    (19)     (13)
Net amortization                           1      (1)      (1)
---------------------------------------------------------------
Net pension income                     $ (57)  $ (51)   $ (42)
===============================================================

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:

                                            Accumulated
                                        Benefit Obligations
                                    -------------------------
                                         2001          2000
-------------------------------------------------------------
                                           (in millions)
Balance at beginning of year             $264          $264
Service cost                                5             4
Interest cost                              24            19
Benefits paid                             (18)          (12)
Actuarial gain and
    employee transfers                    (13)          (11)
Amendments                                 86             -
-------------------------------------------------------------
Balance at end of year                   $348          $264
=============================================================

                                            Plan Assets
                                    -------------------------
                                         2001          2000
-------------------------------------------------------------
                                           (in millions)
Balance at beginning of year             $192          $161
Actual return on plan assets              (24)           25
Employer contributions                     19            18
Benefits paid                             (18)          (12)
-------------------------------------------------------------
Balance at end of year                   $169          $192
=============================================================

      The accrued postretirement costs recognized in the Balance Sheets
were as follows:
                                              2001      2000
---------------------------------------------------------------
                                               (in millions)
Funded status                               $ (179)    $ (72)
Unrecognized transition obligation              45        49
Prior service cost                              82         -
Unrecognized net actuarial gain                 (9)      (35)
Fourth quarter contributions                     8         4
---------------------------------------------------------------
Accrued liability recognized in the
    Balance Sheets                          $  (53)    $ (54)
===============================================================

                                       II-69
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


    Components of the plans' net periodic cost were as follows:

                                        2001    2000     1999
---------------------------------------------------------------
                                            (in millions)
Service cost                             $  5   $  4     $  5
Interest cost                              24     19       18
Expected return on plan assets            (15)   (13)     (11)
Net amortization                            7      4        4
---------------------------------------------------------------
Net postretirement cost                  $ 21  $  14     $ 16
===============================================================

    An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:

                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
                                           (in millions)
Benefit obligation                      $30          $26
Service and interest costs                3            2
===============================================================

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $12
million, $11 million, and $10 million, respectively.

Work Force Reduction Programs

The Company has incurred costs for work force reduction programs totaling $13.0
million, $2.6 million and $5.6 million for the years 2001, 2000 and 1999,
respectively. These costs were deferred and are being amortized in accordance
with regulatory treatment. The unamortized balance of these costs was $11.9
million at December 31, 2001.

3.  CONTINGENCIES AND REGULATORY
    MATTERS

General

The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.

Environmental Litigation

On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in U.S. District Court in Georgia against the Company. The complaint
alleges violations of the New Source Review provisions of the Clean Air Act with
respect to coal-fired generating facilities at the Company's Plants Miller,
Barry, and Gorgas. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The Clean Air Act authorizes civil penalties
of up to $27,500 per day, per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day.

   The EPA concurrently issued to the Company a notice of violation relating to
these specific facilities, as well as Plants Greene County and Gaston. In early
2000, the EPA filed a motion to amend its complaint to add the violations
alleged in its notice of violation. The complaint and the notice of violation
are similar to those brought against and issued to several other electric
utilities. The complaint and the notice of violation allege that the Company
failed to secure necessary permits or install additional pollution control
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. On August 1, 2000, the U.S.
District Court granted the Company's motion to dismiss for lack of jurisdiction
in Georgia. On January 12, 2001, the EPA re-filed its claims against the Company
in federal district court in Birmingham, Alabama.

   The Company's case has been stayed since the spring of 2001, pending a ruling
by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very
similar New Source Review enforcement action against the Tennessee Valley
Authority (TVA). The TVA case involves many of the same legal issues raised by
the actions against the Company. Because the outcome of the TVA case could have


                                     II-70
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


a significant adverse impact on the Company, it is a party to that case as well.
The U.S. District Court in Alabama has indicated that it will revisit the issue
of a continued stay in April 2002.

   The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

Retail Rate Adjustment Procedures

The APSC has adopted rates that provide for periodic adjustments based upon the
Company's earned return on end-of-period retail common equity. The rates also
provide for adjustments to recognize the placing of new generating facilities
into retail service under Rate CNP (Certificated New Plant). Both increases and
decreases have been placed into effect since the adoption of these rates.
Effective July 2001, the Company's retail rates were adjusted by 0.6 percent
under Rate CNP to recover costs for Plant Barry Unit 7, which was placed into
commercial operation on May 1, 2001. Most recently, a 2 percent increase in
retail rates was effective in October 2001 in accordance with the Rate
Stabilization Equalization plan. The rate adjustment procedures allow a return
on common equity range of 13.0 percent to 14.5 percent and limit increases or
decreases in rates to 4 percent in any calendar year.

    In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. During the
years 2001, 2000, and 1999, the Company did not record any such reductions.

    In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000, the APSC certified a seven-year
purchased power agreement pertaining to 615 megawatts of the wholesale
generating facilities which were sold to Southern Power in June 2001 and are
under construction in Autaugaville, Alabama. All of the 615 megawatts will be
delivered beginning in 2003. In addition the APSC certified a seven-year
purchased power agreement with a third party for approximately 630 megawatts;
one half of the power will be delivered beginning in 2003 while the remaining
half is scheduled for delivery beginning in 2004. Rate CNP will adjust retail
rates when the contracted capacity delivery begins.

    In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent of the
budgeted annual amount of natural gas purchases. The Company may not engage in
natural gas hedging activities that extend beyond a rolling 42-month window.

    The Company's ratemaking procedures will remain in effect until the APSC
votes to modify or discontinue them.

4.   COMMITMENTS

Construction Program

During 2001, the Company completed the replacement of the steam generators
at Plant Farley, as well as the construction of new generating capacity at Plant
Barry. Significant construction will continue related to transmission and
distribution facilities and the upgrading of generating plants, including the
expenditures necessary to comply with environmental regulation.

    The Company currently estimates property additions to be $671 million in
2002, $592 million in 2003, and $673 million in 2004.

    In connection with the transfer of the Autaugaville construction project,
the Company has assigned $71 million in vendor equipment contracts to Southern
Power. While the Company could be obligated to assume responsibility for these
contracts if Southern Power fails to meet these commitments, Southern Company
has entered into limited keep-well arrangements whereby Southern Company would
contribute funds to Southern Power either through loans or capital contributions
in order to fund performance by Southern Power as equipment purchaser under
certain contingencies. Southern Company has also guaranteed Southern Power
obligations totaling $6.6 million for the Company's construction of transmission
interconnection facilities to the plant.

    The capital budget is subject to periodic review and revision, and actual
capital costs incurred may vary from estimates because of changes in such


                                      II-71
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


factors as: business conditions; environmental regulations; nuclear plant
regulations; load projections; the cost and efficiency of construction labor,
equipment, and materials; and the cost of capital. In addition there can be no
assurance that costs related to capital expenditures will be fully recovered.

Purchased Power Commitments

The Company has entered into various long-term commitments for the purchase of
electricity. Estimated total long-term obligations at December 31, 2001 were as
follows:
                                        Commitments
                           -----------------------------------
                                           Non-
Year                        Affiliated  Affiliated     Total
----                        ----------------------------------
                                      (in millions)
2002                           $  -        $  -         $  -
2003                             37          16           53
2004                             49          34           83
2005                             49          37           86
2006                             49          38           87
2007 and thereafter             160         142          302
--------------------------------------------------------------
Total commitments              $344        $267         $611
==============================================================

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases these contracts contain provisions for
price escalations, minimum purchase levels, and other financial commitments.
Total estimated long-term obligations at December 31, 2001, were as follows:

Year                                              Commitments
----                                             ---------------
                                                 (in millions)
2002                                                $  795
2003                                                   794
2004                                                   801
2005                                                   571
2006                                                   512
2007 and thereafter                                  1,020
---------------------------------------------------------------
Total commitments                                   $4,493
===============================================================

    In addition, the system service company acts as agent for the five operating
companies and Southern Power with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various indices at the actual time of
delivery; therefore, only the volume commitments are firm. The Company's
committed volumes allocated based on usage projections, as of December 31, 2001,
are as follows:

Year                                            Natural Gas
----                                            -----------
                                                  (MMBtu)
2002                                             77,365,361
2003                                             72,139,927
2004                                             45,600,417
2005                                             22,849,132
2006                                             14,808,334
2007 and thereafter                               5,609,190
------------------------------------------------------------
Total commitments                               238,372,361
============================================================

    Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.

Operating Leases

The Company has entered into rental agreements for coal rail cars, vehicles, and
other equipment with various terms and expiration dates. These expenses totaled
$27.9 million in 2001, $20.9 million in 2000, and $17.8 million in 1999. At
December 31, 2001, estimated minimum rental commitments for noncancellable
operating leases were as follows:

Year                                             Commitments
----                                            ----------------
                                                (in millions)
2002                                              $  27.9
2003                                                 26.5
2004                                                 25.5
2005                                                 21.6
2006                                                 14.4
2007 and thereafter                                  38.1
--------------------------------------------------------------
Total minimum payments                            $ 154.0
==============================================================

     In addition to the rental commitments above, the Company has potential
obligations upon expiration of certain leases with respect to the residual value
of the leased property. These leases expire in 2004 and 2006, and the Company's
maximum obligations are $25.7 million and $66.0 million, respectively. At the
termination of the leases, at the Company's option, the Company may negotiate
an extension, exercise its purchase option, or the property can be sold to a
third party. The Company expects that the fair market value of the leased
property would substantially reduce or eliminate the Company's payments under
the residual value obligation.

5.   JOINT OWNERSHIP AGREEMENTS

The Company and Georgia Power own equally all of the outstanding capital stock
of Southern Electric Generating Company (SEGCO), which owns electric generating
units with a total rated capacity of 1,020 megawatts, together with associated


                                     II-72
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


transmission facilities. The capacity of these units is sold equally to the
Company and Georgia Power under a contract which, in substance, requires
payments sufficient to provide for the operating expenses, taxes, interest
expense and a return on equity, whether or not SEGCO has any capacity and energy
available. The term of the contract extends automatically for two-year periods,
subject to either party's right to cancel upon two year's notice. The Company's
share of expenses totaled $80 million in 2001, $85 million in 2000, and $92
million in 1999 and is included in "Purchased power from affiliates" in the
Statements of Income.

    In addition the Company has guaranteed unconditionally the obligation of
SEGCO under an installment sale agreement for the purchase of certain pollution
control facilities at SEGCO's generating units, pursuant to which $24.5 million
principal amount of pollution control revenue bonds are outstanding. Georgia
Power has agreed to reimburse the Company for the pro rata portion of such
obligation corresponding to its then proportionate ownership of stock of SEGCO
if the Company is called upon to make such payment under its guaranty.

    At December 31, 2001, the capitalization of SEGCO consisted of $58 million
of equity and $86 million of long-term debt on which the annual interest
requirement is $2.2 million. SEGCO paid dividends totaling $0.7 million in 2001,
$5.1 million in 2000, and $4.3 million in 1999 of which one-half of each was
paid to the Company. SEGCO's net income was $7.5 million, $5.9 million, and $5.4
million for 2001, 2000, and 1999, respectively.

    The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 2001, is as follows:

                              Total
                            Megawatt         Company
    Facility (Type)         Capacity        Ownership
 ---------------------    ------------    -------------

 Greene County                 500           60.00%   (1)
    (coal)
 Plant Miller
    Units 1 and 2            1,320           91.84%   (2)
    (coal)
 -----------------------------------------------------------
(1)  Jointly owned with an affiliate, Mississippi Power Company.
(2)  Jointly owned with Alabama Electric Cooperative, Inc.


                              Company         Accumulated
       Facility             Investment        Depreciation
 ---------------------    --------------    ---------------
                                    (in millions)
 Greene County                 $101             $   49
 Plant Miller
    Units 1 and 2               747                326
 ----------------------------------------------------------

6.   LONG-TERM POWER SALES AGREEMENTS

General

The Company and the other operating companies of Southern Company have entered
into long-term contractual agreements for the sale and lease of capacity and
energy to certain non-affiliated utilities located outside the system's service
area. These agreements -- expiring at various dates discussed below -- are firm
and related to specific generating units. Because the energy is generally
provided at cost under these agreements, profitability is primarily affected by
capacity revenues.

    Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority
(JEA). Under these agreements approximately 1,237 megawatts of capacity are
scheduled to be sold through 2010. The Company's capacity revenues amounted to
$125 million in 2001, $127 million in 2000, and $122 million in 1999.

Alabama Municipal Electric Authority (AMEA)
Capacity Contracts

In 1986 the Company entered into a firm power sales contract with AMEA entitling
AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for a period
of 15 years (1986 Contract). In October 1991 the Company entered into a second
firm power sales contract with AMEA entitling AMEA to scheduled amounts of
additional capacity (to a maximum 80 megawatts) for a period of 15 years (1991
Contract). Under the terms of the contracts, the Company received payments from
AMEA representing the net present value of the revenues associated with the
respective capacity entitlements, discounted at effective annual rates of 9.96
percent and 11.19 percent for the 1986 and 1991 contracts, respectively. The
1986 contract expired in July 2001, however, the payments for the 1991 contract
will continue to be recognized as operating revenues and the discounts will be
amortized to other interest expense as scheduled capacity is made available over
the terms of the contract.

     To secure AMEA's advance payments and the Company's performance obligation
under the contracts, the Company issued and delivered to an escrow agent first
mortgage bonds representing the maximum amount of liquidated damages payable by
the Company in the event of a default under the contracts. No principal or
interest is payable on such bonds unless and until a default by the Company


                                     II-73
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


occurs. As the liquidated damages decline, a portion of the bond equal to the
decrease is returned to the Company. At December 31, 2001, $38.1 million of the
1991 bond was held by the escrow agent under the contract.

7.   INCOME TAXES

At December 31, 2001, the tax-related regulatory assets and liabilities were
$335 million and $203 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized interest. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.

    Details of the income tax provisions are as follows:

                                     2001       2000       1999
                                 --------------------------------
                                           (in millions)
Total provision for income taxes:
Federal --
 Current                             $234       $168       $194
  Deferred                            (20)        60         24
-----------------------------------------------------------------
                                      214        228        218
-----------------------------------------------------------------
State --
  Current                              37         27         19
  Deferred                             (2)         7          5
-----------------------------------------------------------------
                                       35         34         24
-----------------------------------------------------------------
Total                                $249       $262       $242
=================================================================

    The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:


                                                 2001      2000
                                               ------------------
                                                  (in millions)
Deferred tax liabilities:
  Accelerated depreciation                      $ 1,034    $ 992
  Property basis differences                        390      405
  Fuel cost adjustment                               28       93
  Premium on reacquired debt                         29       30
  Pensions                                           89       75
  Other                                              23       12
-----------------------------------------------------------------
Total                                             1,593    1,607
-----------------------------------------------------------------
Deferred tax assets:
  Capacity prepayments                               13       18
  Other deferred costs                               14       14
  Postretirement benefits                            21       24
  Unbilled revenue                                   18       23
  Other                                              93       81
-----------------------------------------------------------------
Total                                               159      160
-----------------------------------------------------------------
Total deferred tax liabilities, net               1,434    1,447
Portion included in current liabilities, net       (47)      (46)
-----------------------------------------------------------------
Accumulated deferred income taxes
  in the Balance Sheets                          $1,387   $1,401
=================================================================

    Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $11 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.

    A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                       2001     2000     1999
                                     --------------------------
Federal statutory rate                 35.0%    35.0%    35.0%
State income tax,
  net of federal deduction              3.5      3.1      2.4
Non-deductible book
  depreciation                          1.5      1.4      1.6
Differences in prior years'
  deferred and current tax rates       (1.3)    (1.3)    (1.3)
Other                                  (0.5)    (0.7)    (0.9)
---------------------------------------------------------------
Effective income tax rate              38.2%    37.5%    36.8%
===============================================================

    Southern Company files a consolidated federal and certain state income tax
returns. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.


                                     II-74
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


8.   CAPITALIZATION

Mandatorily Redeemable Preferred Securities

Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:

              Date of                                 Maturity
               Issue    Amount      Rate     Notes      Date
            ---------------------------------------------------
                       (millions)           (millions)
Trust I       1/1996    $ 97      7.375%      $100       3/2026
Trust II      1/1997     200      7.60         206      12/2036
Trust III     2/1999      50      Auction       52       2/2029

    Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above. The distribution rate of Trust III's auction rate securities was 3.60% at
January 1, 2002.

    The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.

    The Trusts are subsidiaries of the Company and accordingly are consolidated
in the Company's financial statements.

Pollution Control Bonds

Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. The Company is required to make payments sufficient for the
authorities to meet principal and interest requirements of such bonds. With
respect to $114.2 million of such pollution control obligations, the Company has
authenticated and delivered to the trustees a like principal amount of first
mortgage bonds as security for its obligations under the installment purchase
agreements. No principal or interest on these first mortgage bonds is payable
unless and until a default occurs on the installment purchase agreements.

   In 2001, the Company sold, through a public authority, $20 million of
pollution control bonds, the proceeds of which were used to pay certain costs
incurred in connection with the acquisition, construction, installation, and
equipping of certain local district heating facilities and sewage and solid
waste facilities at two of the Company's generation facilities.

Senior Notes

In August 2001 the Company issued $442 million of unsecured senior notes, the
proceeds of which were used to redeem the $131.5 million outstanding principal
of its First Mortgage Bonds, 9% Series due December 1, 2004 and for other
corporate purposes including the repayment of a portion of its short-term
indebtedness. All of the Company's senior notes are, in effect, subordinate to
all secured debt of the Company, including its first mortgage bonds.

Capitalized Leases

The estimated aggregate annual maturities of capitalized lease obligations
through 2006 are as follows: $0.9 million in 2002, $0.9 million in 2003, $1.0
million in 2004, $0.4 million in 2005, and $0.1 million in 2006.

Securities Due Within One Year

A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:

                                            2001        2000
                                        ----------------------
                                             (in thousands)
  First mortgage bond maturities
     and redemptions                      $4,498        $  -
  Other long-term debt maturities            884         844
  ------------------------------------------------------------
  Total long-term debt due within
     one year                             $5,382        $844
  ============================================================

    The annual first mortgage bond improvement fund requirement is 1 percent of
the aggregate principal amount of bonds of each series authenticated, so long as
a portion of that series is outstanding, and may be satisfied by the deposit of
cash and/or reacquired bonds, the certification of unfunded property additions,
or a combination thereof.

Bank Credit Arrangements

The Company maintains committed lines of credit in the amount of $964 million
(including $454 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$574 million expire at various times during 2002 and $390 million expire in

                                     II-75
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


2004. In certain cases, such lines require payment of a commitment fee based on
the unused portion of the commitment or the maintenance of compensating balances
with the banks. Because the arrangements are based on an average balance, the
Company does not consider any of its cash balances to be restricted as of any
specific date. Moreover, the Company borrows from time to time pursuant to
arrangements with banks for uncommitted lines of credit. The amount of
commercial paper outstanding at December 31, 2001 was $10 million.

    At December 31, 2001, the Company had regulatory approval to have
outstanding up to $1 billion of short-term borrowings.

Assets Subject to Lien

The Company's mortgage, as amended and supplemented, securing the first mortgage
bonds issued by the Company, constitutes a direct lien on substantially all of
the Company's fixed property and franchises.

Dividend Restrictions

The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 2001, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.

9.    NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act of 1988 (the Act), the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at Plant
Farley. The Act provides funds up to $9.5 billion for public liability claims
that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $200 million by American Nuclear Insurers (ANI),
with the remaining coverage provided by a mandatory program of deferred premiums
which could be assessed, after a nuclear incident, against all owners of nuclear
reactors. The Company could be assessed up to $88 million per incident for each
licensed reactor it operates but not more than an aggregate of $10 million per
incident to be paid in a calendar year for each reactor. Such maximum
assessment, excluding any applicable state premium taxes, for the Company is
$176 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year.

    The Company is a member of Nuclear Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.

    Additionally, the Company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.

    NEIL also covers the additional cost that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years.

    Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $35 million.

    Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. However, both companies revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.

    For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies shall be
dedicated first for the sole purpose of placing the reactor in a safe and stable
condition after an accident. Any remaining proceeds are to be applied next
toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the Company or
to its bond trustees as may be appropriate under the policies and applicable
trust indentures.

    All retrospective assessments, whether generated for liability, property or
replacement power may be subject to applicable state premium taxes.


                                     II-76
<PAGE>
NOTES (continued)
Alabama Power Company 2001 Annual Report


10.   QUARTERLY FINANCIAL INFORMATION
      (Unaudited)

Summarized quarterly financial data for 2001 and 2000 are as follows:

                                                     Net Income
                                                       After
                                                     Dividends
       Quarter            Operating    Operating    on Preferred
        Ended              Revenues      Income        Stock
--------------------    -----------------------------------------
                                     (in millions)

March 2001                  $  850         $180          $ 70
June 2001                      904          194            75
September 2001               1,061          362           180
December 2001                  772          175            62

March 2000                 $   746         $172          $ 68
June 2000                      900          229           103
September 2000               1,137          390           209
December 2000                  884          151            40
-----------------------------------------------------------------

The Company's business is influenced by seasonal weather conditions.


                                     II-77


<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Alabama Power Company 2001 Annual Report


----------------------------------------------------------------------------------------------------------------------------
                                                      2001            2000            1999             1998            1997
----------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>             <C>             <C>              <C>             <C>
Operating Revenues (in thousands)               $3,586,390      $3,667,461      $3,385,474       $3,386,373      $3,149,111
Net Income after Dividends
  on Preferred Stock (in thousands)               $386,729        $419,916        $399,880         $377,223        $375,939
Cash Dividends
  on Common Stock (in thousands)                  $393,900        $417,100        $399,600         $367,100        $339,600
Return on Average Common Equity (percent)            11.89           13.58           13.85            13.63           13.76
Total Assets (in thousands)                    $10,418,301     $10,366,105      $9,648,704       $9,225,698      $8,812,867
Gross Property Additions (in thousands)           $635,540        $870,581        $809,044         $610,132        $451,167
----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                             $3,310,877      $3,195,772      $2,988,863       $2,784,067      $2,750,569
Preferred stock                                    317,512         317,512         317,512          317,512         255,512
Company obligated mandatorily
  redeemable preferred securities                  347,000         347,000         347,000          297,000         297,000
Long-term debt                                   3,742,346       3,425,527       3,190,378        2,646,566       2,473,202
----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)   $7,717,735      $7,285,811      $6,843,753       $6,045,145      $5,776,283
============================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                   42.9            43.9            43.7             46.1            47.6
Preferred stock                                        4.1             4.4             4.6              5.3             4.4
Company obligated mandatorily
  redeemable preferred securities                      4.5             4.8             5.1              4.9             5.2
Long-term debt                                        48.5            46.9            46.6             43.7            42.8
----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)        100.0           100.0           100.0            100.0           100.0
============================================================================================================================
Security Ratings:
First Mortgage Bonds -
   Moody's                                              A1              A1              A1               A1              A1
   Standard and Poor's                                   A               A              A+               A+              A+
   Fitch                                                A+             AA-             AA-              AA-             AA-
Preferred Stock -
   Moody's                                            Baa1              a2              a2               a2              a2
   Standard and Poor's                                BBB+            BBB+              A-                A               A
   Fitch                                                A-               A               A                A              A+
Unsecured Long-Term Debt -
   Moody's                                              A2              A2              A2               A2              A2
   Standard and Poor's                                   A               A               A                A               A
   Fitch                                                 A              A+              A+               A+              A+
============================================================================================================================
Customers (year-end):
Residential                                      1,139,542       1,132,410       1,120,574        1,106,217       1,092,161
Commercial                                         196,617         193,106         188,368          182,738         177,362
Industrial                                           4,728           4,819           4,897            5,020           5,076
Other                                                  751             745             735              733             728
----------------------------------------------------------------------------------------------------------------------------
Total                                            1,341,638       1,331,080       1,314,574        1,294,708       1,275,327
============================================================================================================================
Employees (year-end):                                6,706           6,871           6,792            6,631           6,531
----------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                                             II-78



<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Alabama Power Company 2001 Annual Report


------------------------------------------------------------------------------------------------------------------------------
                                                        2001            2000            1999             1998            1997
------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S>                                              <C>              <C>            <C>              <C>               <C>
Residential                                      $ 1,138,499      $1,222,509     $ 1,145,646      $ 1,133,435       $ 997,507
Commercial                                           829,760         854,695         807,098          779,169         724,148
Industrial                                           763,934         859,668         843,090          853,550         775,591
Other                                                 15,480          15,835          15,283           14,523          13,563
------------------------------------------------------------------------------------------------------------------------------
Total retail                                       2,747,673       2,952,707       2,811,117        2,780,677       2,510,809
Sales for resale  - non-affiliates                   485,974         461,730         415,377          448,973         431,023
Sales for resale  - affiliates                       245,189         166,219          92,439          103,562         161,795
------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity           3,478,836       3,580,656       3,318,933        3,333,212       3,103,627
Other revenues                                       107,554          86,805          66,541           53,161          45,484
------------------------------------------------------------------------------------------------------------------------------
Total                                             $3,586,390      $3,667,461      $3,385,474       $3,386,373      $3,149,111
==============================================================================================================================

Kilowatt-Hour Sales (in thousands):
Residential                                       15,880,971      16,771,821      15,699,081       15,794,543      14,336,408
Commercial                                        12,798,711      12,988,728      12,314,085       11,904,509      11,330,312
Industrial                                        20,460,022      22,101,407      21,942,889       21,585,117      20,727,912
Other                                                198,102         205,827         201,149          196,647         180,389
------------------------------------------------------------------------------------------------------------------------------
Total retail                                      49,337,806      52,067,783      50,157,204       49,480,816      46,575,021
Sales for resale  - non-affiliates                15,277,839      14,847,533      12,437,599       11,840,910      12,329,480
Sales for resale  - affiliates                     8,843,094       5,369,474       5,031,781        5,976,099       8,993,326
------------------------------------------------------------------------------------------------------------------------------
Total                                             73,458,739      72,284,790      67,626,584       67,297,825      67,897,827
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                             7.17            7.29            7.30             7.18            6.96
Commercial                                              6.48            6.58            6.55             6.55            6.39
Industrial                                              3.73            3.89            3.84             3.95            3.74
Total retail                                            5.57            5.67            5.60             5.62            5.39
Sales for resale                                        3.03            3.11            2.91             3.10            2.78
Total sales                                             4.74            4.95            4.91             4.95            4.57
Residential Average Annual
  Kilowatt-Hour Use Per Customer                      13,981          14,875          14,097           14,370          13,254
Residential Average Annual
  Revenue Per Customer                             $1,002.30       $1,084.26       $1,028.76        $1,031.21         $922.21
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                      12,153          12,122          11,379           11,151          11,151
Maximum Peak-Hour Demand (megawatts):
Winter                                                 9,300           9,478           8,863            7,757           8,478
Summer                                                10,241          11,019          10,739           10,329           9,778
Annual Load Factor (percent)                            62.5            59.3            59.7             62.9            62.7
Plant Availability (percent):
Fossil-steam                                            87.1            89.4            80.4             85.6            86.3
Nuclear                                                 83.7            88.3            91.0             80.2            88.8
------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                    56.8            63.0            64.1             65.3            65.7
Nuclear                                                 15.8            16.9            17.8             16.3            17.9
Hydro                                                    5.1             2.9             4.7              6.9             7.5
Oil and gas                                             10.7             4.9             1.1              1.5             0.7
Purchased power -
  From non-affiliates                                    4.4             4.6             4.5              3.3             2.4
  From affiliates                                        7.2             7.7             7.8              6.7             5.8
------------------------------------------------------------------------------------------------------------------------------
Total                                                  100.0           100.0           100.0            100.0           100.0
==============================================================================================================================
</TABLE>


                                                             II-79





<PAGE>

                             GEORGIA POWER COMPANY
                               FINANCIAL SECTION

                                      II-80
<PAGE>


MANAGEMENT'S REPORT
Georgia Power Company 2001 Annual Report


The management of Georgia Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with accounting principles generally
accepted in the United States and necessarily include amounts that are based on
the best estimates and judgments of management. Financial information throughout
this annual report is consistent with the financial statements.

     The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls based upon the recognition that the cost of the
system should not exceed its benefits. The Company believes that its system of
internal accounting controls maintains an appropriate cost/benefit relationship.

     The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.

     The audit committee of the board of directors, which is composed of three
independent directors, provides a broad overview of management's financial
reporting and control functions. At least three times a year this committee
meets with management, the internal auditors, and the independent public
accountants to ensure that these groups are fulfilling their obligations and to
discuss auditing, internal control and financial reporting matters. The internal
auditors and the independent public accountants have access to the members of
the audit committee at any time.

     Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.

     In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with accounting principles generally
accepted in the United States.



/s/David M. Ratcliffe
David M. Ratcliffe
President and Chief Executive Officer


/s/Thomas A. Fanning
Executive Vice President, Treasurer
and Chief Financial Officer
February 13, 2002

                                       II-81

<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Georgia Power Company:


We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 2001 and 2000, and the related statements
of income, comprehensive income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.  We believe that our audits provide a reasonable basis
for our opinion.

      In our opinion, the financial statements (pages II-93 through II-113)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

      As explained in Note 1 to the financial statements, effective January 1,
2001, Georgia Power Company changed its method of accounting for derivative
instruments and hedging activities.



/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002

                                       II-82



<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 2001 Annual Report


RESULTS OF OPERATIONS

Earnings

Georgia Power Company's 2001 earnings totaled $610 million, representing a $51
million (9.1 percent) increase over 2000. Although operating income is lower due
to the impact of mild weather on retail revenues, overall net income improved
due to lower financing costs and non-operating expenses and a lower effective
tax rate resulting from various factors including property donations and
positive resolution of outstanding tax issues. The Company's 2000 earnings
totaled $559 million, representing an $18 million (3.3 percent) increase over
1999. This earnings increase was primarily due to higher retail and wholesale
sales and continued control of operating expenses, partially offset by
additional accelerated amortization of regulatory assets allowed under the
second year of a Georgia Public Service Commission (GPSC) three-year retail rate
order.

Revenues

Operating revenues in 2001 and the amount of change from the prior year are as
follows:

                                                Increase
                                               (Decrease)
                                             From Prior Year
                                   Amount   -------------------
                                    2001        2001      2000
                                    ----    -------------------
   Retail -                                     (in millions)
   Base revenues                     $3,102     $(17)        $ 84
   Fuel cost recovery                 1,247       49          183
-------------------------------------------------------------------
Total retail                          4,349       32          267
-------------------------------------------------------------------
Sales for resale -
   Non-affiliates                       366       68           88
   Affiliates                           100        4           20
-------------------------------------------------------------------
Total sales for resale                  466       72          108
-------------------------------------------------------------------
Other operating revenues                151       (9)          39
-------------------------------------------------------------------
Total operating revenues             $4,966      $95         $414
===================================================================
Percent change                                   2.0%         9.3%
-------------------------------------------------------------------

     Retail base revenues of $3.1 billion in 2001 decreased $17 million (0.5
percent) from 2000 primarily due to a 2.5 percent decrease in retail sales from
the prior year. Milder-than-normal weather and a slowdown in the economy
contributed to the decline in such sales. Retail base revenues of $3.1 billion
in 2000 increased $84 million (2.8 percent) from 1999 primarily due to a 4.9
percent increase in sales. Under the prior GPSC retail rate order, the Company
recorded $44 million of revenue subject to refund for estimated earnings above
12.5 percent retail return on common equity in 2000. These refunds were made to
customers in 2001. See Note 3 to the financial statements under "Retail Rate
Orders" for additional information.

     Electric rates include provisions to adjust billings for fluctuations in
fuel costs, the energy component of purchased power costs, and certain other
costs. Under these fuel cost recovery provisions, fuel revenues generally equal
fuel expenses -- including the fuel component of purchased energy -- and do not
affect net income. However, cash flow is affected by the untimely recovery of
these receivables. As of December 31, 2001, the Company had $162 million in
underrecovered fuel costs. The Company is currently collecting these
underrecovered fuel costs under a GPSC rate order issued on May 24, 2001. The
fuel cost recovery rate was increased effective June 2001 to allow for a
24-month recovery of the deferred underrecovered fuel costs.

     Wholesale revenues from sales to non-affiliated utilities increased in 2001
and 2000 as follows:

                                  2001       2000      1999
                                -----------------------------
                                        (in millions)
Long-term contracts               $ 61       $ 55      $ 55
Other sales                        305        243       155
-------------------------------------------------------------
Total                             $366       $298      $210
=============================================================

     Revenues from long-term contracts increased slightly in 2001 due to
increased energy sales while remaining constant in 2000. See Note 7 to the
financial statements for further information regarding these sales. Revenues
from other non-affiliated sales increased $62 million (25.5 percent) primarily
due to increases in off-system sale transactions that were generally offset by
corresponding purchase transactions. These transactions had no significant
effect on income.

     Revenues from sales to affiliated companies within the Southern electric
system, as well as purchases of energy, will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These transactions do not have a significant impact on earnings.

     Other operating revenues in 2001 decreased $9 million (5.3 percent)
primarily due to lower gains on the sale of generating plant emission
allowances, partially offset by increased revenues from the transmission of
electricity and from the rental of electric equipment and property. Other


                                       II-83
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


operating revenues in 2000 increased $39 million (33 percent) primarily due to
increased revenues from the transmission of electricity and gains on the sale of
generating plant emission allowances. Under a GPSC order, $28 million of the
gains on emission allowance sales in 2000 were used to reduce recoverable fuel
costs and, as such, did not affect earnings.

     Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:
                                         Percent Change
                                      ----------------------
                            2001
                            KWH         2001        2000
                         --------- ------------------------
                         (in billions)
Residential                   20.1      (2.8)%       6.6%
Commercial                    26.5       3.4         8.1
Industrial                    25.4      (8.0)        0.9
Other                          0.6       2.5         3.2
                            ------
Total retail                  72.6      (2.5)        4.9
                            ------
Sales for resale -
   Non-affiliates              8.1      25.5        27.7
   Affiliates                  3.1      28.7        35.6
                            ------
Total sales for resale        11.2      26.3        29.8
                            ------
Total sales                   83.8       0.5         7.1
                            ======
------------------------------------------------------------

     Residential sales decreased 2.8 percent due to milder-than-normal weather.
Commercial sales increased 3.4 percent due to a 2.8 percent increase in
customers, while industrial sales decreased 8.0 percent due to an economic
slowdown. Residential and commercial sales increased 6.6 percent and 8.1
percent, respectively, in 2000 due to warmer summer temperatures and colder
winter weather. Strong regional economic growth was also a factor in the
increase in commercial sales. Industrial sales remained fairly constant.

Expenses

Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net KWH generated were as follows:

                                      2001      2000     1999
                                    --------------------------
Total generation
   (billions of KWH)                  68.9      73.6     69.3
Sources of generation
   (percent) --
     Coal                             74.9      75.8     75.5
     Nuclear                          23.2      21.2     21.6
     Hydro                             1.4       0.8      1.0
     Oil and gas                       0.5       2.2      1.9
Average cost of fuel per net
   KWH generated
     (cents) --                       1.38      1.39     1.34
--------------------------------------------------------------

     Fuel expense decreased 7.7 percent due to a decrease in generation because
of lower energy demands and a slightly lower average cost of fuel. Fuel expense
increased 10.7 percent in 2000 due to an increase in generation to meet higher
energy demands, a decrease in generation from hydro plants, and a higher average
cost of fuel.

     Purchased power expense increased $175 million (29.4 percent) in 2001
primarily due to an increase in off-system purchases used to meet off-system
sales commitments. These transactions had no significant effect on earnings.
Purchased power expense in 2000 increased $206 million (53 percent) over the
prior year due to higher retail energy demands and off-system purchase
transactions used to meet off-system sales transactions.

     In 2001, other operation and maintenance expenses increased $41 million
(3.4%) due to additional severance costs, increased scheduled generating plant
maintenance, and higher uncollectible account expense. Other operation and
maintenance expenses in 2000 increased slightly over those in 1999. Increased
line maintenance, customer assistance and sales expense, and severance costs
were partially offset by decreased generating plant maintenance and decreased
employee benefit provisions.

     Depreciation and amortization decreased $19 million in 2001 primarily due
to lower accelerated amortization under the third year of a GPSC retail rate
order. Depreciation and amortization increased $66 million in 2000 primarily due
to $50 million of additional accelerated amortization of regulatory assets
required under the second year of the GPSC retail rate order and increased plant
in service.

                                       II-84
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


     Other, net increased in 2001 due to gains realized on sales of assets and a
decrease in charitable contributions. Other, net decreased in 2000 due to an
increase in charitable contributions.

     Interest expense, net decreased in 2001 primarily due to lower interest
rates that offset new financing costs. Interest expense, net increased in 2000
due to the issuance of additional senior notes during 2000. The Company
refinanced or retired $775 million and $179 million of securities in 2001 and
2000, respectively. Distributions on preferred securities of subsidiary
companies remained unchanged in 2001 and decreased $7 million in 2000 due to the
redemption of $100 million of preferred securities in December 1999.

Effects of Inflation

The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plants with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.

FUTURE EARNINGS POTENTIAL

General

The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including regulatory matters and energy sales.

     Growth in energy sales is subject to a number of factors which
traditionally have included changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, weather,
competition, initiatives to increase sales to existing customers, and the rate
of economic growth in the Company's service area.

     In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income
of approximately $60 million in 2001. Future pension income is dependent on
several factors including trust earnings and changes to the plan. For the
Company, pension income is a component of the regulated rates and does not have
a significant effect on net income. For additional information, see Note 2 to
the financial statements.

     The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
State of Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC under cost-based regulatory principles.

     On December 20, 2001, the GPSC approved a new three-year retail rate order
for the Company ending December 31, 2004. Under the terms of the order, earnings
will be evaluated annually against a retail return on common equity range of 10
percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent
return will be applied to rate refunds, with the remaining one-third retained by
the Company. Retail rates were decreased by $118 million effective January 1,
2002. Pursuant to a previous three-year accounting order, the Company recorded
$336 million of accelerated cost amortization and interest thereon which has
been credited to a regulatory liability account as mandated by the GPSC. Under
the new rate order, the accelerated amortization and the interest will be
amortized equally over three years as a credit to expense beginning in 2002. The
Company will not file for a general base rate increase unless its projected
retail return on common equity falls below 10 percent. Georgia Power is required
to file a general rate case on July 1, 2004, in response to which the GPSC would
be expected to determine whether the rate order should be continued, modified,
or discontinued. See Note 3 to the financial statements under "Retail Rate
Orders" for additional information.

     The Company has entered into power purchase agreements which will result in
higher capacity and operating and maintenance payments in future years. Under
the new retail rate order, these costs will be reflected in rates evenly over
the next three years. See Note 4 to the financial statements under "Purchased
Power Commitments" for additional information.

                                       II-85
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


    Georgia Power had three new generation projects under construction during
2001. They included two units at Plant Dahlberg, a ten-unit, 800 megawatt
combustion turbine facility; two combined cycle units totaling 1,132 megawatts
at Plant Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle
facility. All three of these projects have been transferred to Southern Power
Company, a new Southern Company subsidiary formed in 2001 to construct, own, and
manage wholesale generating assets in the Southeast. The ten Dahlberg units and
two Goat Rock units were transferred in 2001 and the transfer of the two Wansley
units was completed in January 2002.

     The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.

     Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. See "Environmental Issues" for further discussion of these matters.

Industry Restructuring

The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are affected by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers.

     Although the Energy Act does not permit retail customer access, it has been
a major catalyst for recent restructuring and consolidations taking place within
the utility industry. Numerous federal and state initiatives are in varying
stages that promote wholesale and retail competition. Among other things, these
initiatives allow customers to choose their electricity provider. Some states
have approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While restructuring and competition
initiatives have been discussed in Georgia, none have been enacted. Enactment
would require numerous issues to be resolved, including significant ones
relating to recovery of any stranded investments, full cost recovery of energy
produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation. The Company
does compete with other electric suppliers within the state. In Georgia, most
new retail customers with at least 900 kilowatts of connected load may choose
their electricity supplier.

     In December 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encouraged utilities owning transmission systems to form RTOs on a voluntary
basis. Southern Company has submitted a series of status reports informing the
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing an RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to
have a material impact on Georgia Power's financial statements. The outcome of
this matter cannot now be determined.

Accounting Policies

Critical Policy

Georgia Power's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operations is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets, including plant, have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.



                                       II-86
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


New Accounting Standards

Effective January 2001, Georgia Power adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change -- effective April
1, 2002 -- in accounting for certain contracts related to fuel supplies that
contain quantity options. These contracts will be accounted for as derivatives
and marked to market. However, due to the existence of specific cost-based fuel
recovery clauses for the Company, this change is not expected to have a material
impact on net income.

    In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets (but not
those acquired in a business combination) should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No. 142 effective January 1, 2002 with
no material impact on the Company's financial statements.

   Also, in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning nuclear
plants. The liability for an asset's future retirement must be recorded in the
period in which the liability is incurred. The cost must be capitalized as part
of the related long-lived asset and depreciated over the asset's useful life.
Changes in the liability resulting from the passage of time will be recognized
as operating expenses. Statement No. 143 must be adopted by January 1, 2003. The
Company has not yet quantified the impact of adopting Statement No. 143 on its
financial statements.

FINANCIAL CONDITION

Plant Additions

In 2001, gross utility plant additions were $1.4 billion. These additions were
primarily related to transmission and distribution facilities, the purchase of
nuclear fuel, and the construction of additional combustion turbine and combined
cycle units. The funds needed for gross property additions are currently
provided from operations, short-term and long-term debt, and capital
contributions from Southern Company. The Statements of Cash Flows provide
additional details.

Credit Rating Risk

The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are certain physical electricity sale contracts that could
require collateral -- but not termination -- in the event of a credit rating
change to below investment grade. At December 31, 2001, the maximum potential
collateral requirements were approximately $112 million.

Exposure to Market Risks

The Company is exposed to market risks, including changes in interest rates,
currency exchange rates, and certain commodity prices. To manage the volatility
attributable to these exposures, the Company nets the exposures to take
advantage of natural offsets and enters into various derivative transactions for
the remaining exposures pursuant to the Company's policies in areas such as
counterparty exposure and hedging practices. Company policy is that derivatives
are to be used primarily for hedging purposes. Derivative positions are
monitored using techniques that include market valuation and sensitivity
analysis.

     The Company's market risk exposures relative to interest rate changes have
not changed materially compared to the previous reporting period. In addition,
the Company is not aware of any facts or circumstances that would significantly
affect such exposures in the near term.

                                       II-87
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


     If the Company sustained a 100 basis point change in interest rates for all
variable rate long-term debt, the change would affect annualized interest
expense by approximately $13 million at December 31, 2001. Based on the
Company's overall interest rate exposure at December 31, 2001, including
derivative and other interest rate sensitive instruments, a near-term 100 basis
point change in interest rates would not materially affect the Company's
financial statements.

     Due to cost-based rate regulations, the Company has limited exposure to
market volatility in interest rates, commodity fuel prices, and prices of
electricity. To mitigate residual risks relative to movements in electricity
prices, the Company entered into fixed price contracts for the purchase and sale
of electricity through the wholesale electricity market and to a lesser extent
similar contracts for gas purchases. Realized gains and losses are recognized in
the Statements of Income as incurred. At December 31, 2001, exposure from these
activities was not material to the Company's financial statements. Fair value of
changes in energy trading contracts and year-end valuations are as follows:

                             Changes During the Year
----------------------------------------------------
                                     Fair Value
----------------------------------------------------
                                   (in millions)
Contracts beginning of year             $0.9
Contracts realized or settled           (0.6)
New contracts at inception                 -
Changes in valuation techniques            -
Current period changes                   0.1
----------------------------------------------------
Contracts end of year                   $0.4
===================================================

    All of these contracts are actively quoted and mature within one year. For
additional information, see Note 1 to the financial statements under "Financial
Instruments."

Financing Activities

In 2001, the Company's financing costs decreased due to lower interest rates
despite the issuance of new debt during the year. New issues during 1999 through
2001 totaled $1.9 billion and retirement or repayment of higher-cost securities
totaled $1.7 billion.

     The proceeds from assets transferred to Southern Power were used to reduce
short-term debt and return capital to the Southern Company that was used during
the construction of these projects.

     Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 1999 through 2001, as of year-end, were as
follows:
                                   2001        2000       1999
                                --------------------------------
Composite interest rate
   on long-term debt               4.26%       5.90%      5.48%
Composite preferred
   stock dividend rate             4.60        4.60       4.60
Composite preferred
   securities dividend rate        7.49        7.49       7.49
----------------------------------------------------------------

Liquidity and Capital Requirements

Cash provided from operations remained constant in 2001.

     The Company estimates that construction expenditures for the years 2002
through 2004 will total $1.0 billion, $0.8 billion, and $0.8 billion,
respectively. Investments primarily in additional transmission and distribution
facilities and equipment to comply with environmental requirements are planned.

     Cash requirements for redemptions announced and maturities of long-term
debt are expected to total $666 million during 2002 through 2004.

     As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
decommissioning costs. The amount to be funded under the new GPSC rate order is
$8.7 million each year in 2002, 2003, and 2004. For additional information
concerning nuclear decommissioning costs, see Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning."

Sources of Capital

The Company expects to meet future capital requirements primarily using funds
generated from operations and equity funds from Southern Company and by the
issuance of new debt and equity securities, term loans, and short-term
borrowings. The Company plans to request new financing authority from the GPSC
in early 2002 to allow for the issuance of new long-term securities. To meet
short-term cash needs and contingencies, the Company had approximately $1.8
billion of unused credit arrangements with banks at the beginning of 2002. See
Note 9 to the financial statements under "Bank Credit Arrangements" for
additional information.

                                     II-88
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


     The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $707.6 million of commercial
paper.

     Recently, the Company has relied on the issuance of unsecured debt and
trust preferred securities, in addition to unsecured pollution control bonds
issued for its benefit by public authorities, to meet its long-term external
financing requirements. In years past, the Company issued first mortgage bonds,
mortgage backed pollution control bonds and preferred stock to fund its external
requirements. The amount outstanding of these securities has been steadily
declining during the last four years.

Other Capital Requirements

In addition to the funds needed for the construction program, approximately $666
million will be required by the end of 2004 for maturities of long-term debt.
Also, the Company will continue to retire higher-cost debt and preferred
securities and replace these obligations with lower-cost capital if market
conditions permit.

   These capital requirements, lease obligations, and purchase commitments --
discussed in Notes 4 and 9 to the financial statements -- are as follows:

                                    2002      2003      2004
---------------------------------------------------------------
                                          (in millions)
Bonds -
   First mortgage                 $    2    $    -       $  -
   Pollution control                   8         -          -
Notes                                300       350          -
Leases -
   Capital                             2         2          2
   Operating                          15        15         15
Purchase commitments
    Fuel                           1,234     1,115        617
    Purchased power                  163       223        278
---------------------------------------------------------------

     At the beginning of 2002, Georgia Power had not used any of its available
credit arrangements. Credit arrangements are as follows:

                                         Expires
                             ----------------------------
      Total       Unused         2002     2003 & beyond
   ------------------------------------------------------
                          (in millions)
    $1,765        $1,765        $1,265            $500
   ------------------------------------------------------

ENVIRONMENTAL ISSUES

Clean Air Legislation

In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company's subsidiaries,
including the Company. Reductions in sulfur dioxide and nitrogen oxide emissions
from fossil-fired generating plants were required in two phases. Phase I
compliance began in 1995.

     Southern Company's subsidiaries, including the Company, achieved Phase I
compliance at the affected units by primarily switching to low-sulfur coal and
with some equipment upgrades. Construction expenditures for the Company's Phase
I compliance totaled approximately $167 million.

     Phase II sulfur dioxide compliance was required in 2000. Southern Company's
subsidiaries, including the Company, used emission allowances and fuel switching
to comply with Phase II requirements. Also, equipment to control nitrogen oxide
emissions was installed on additional system fossil-fired units as necessary to
meet Phase II limits and ozone non-attainment requirements for metropolitan
Atlanta through 2000. Compliance for Phase II and initial ozone non-attainment
requirements increased total construction expenditures for the Company through
2000 by approximately $39 million.

     In 2000, the State of Georgia established new emission limits designed to
help bring the Atlanta area into compliance with the national one-hour standard
for ground-level ozone. The limits include new emission standards for seven of
the Company's generating stations and will go into effect in May 2003.
Construction expenditures for the Company's compliance with these new rules are
currently estimated at approximately $699 million with a total of $345 million
remaining to be spent.

                                     II-89
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


     A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.

     In July 1997, the Environmental Protection Agency (EPA) revised the
national ambient air quality standards for ozone and particulate matter. This
revision made the standards significantly more stringent. In the subsequent
litigation of these standards, the U.S. Supreme Court found the EPA's
implementation program for the new ozone standard unlawful and remanded it to
the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals
is considering other legal challenges to these standards. If the standards are
eventually upheld, implementation could be required by 2007 to 2010.

     In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rule affects 21 states including
Georgia. Compliance is required by May 31, 2004. The EPA proposed rules for
Georgia on February 13, 2002. The EPA's proposal includes a May 1, 2005
implementation date for Georgia. The Company plans to demonstrate compliance
based largely on NOx controls already installed to meet the Atlanta
non-attainment requirements, coupled with the purchase of NOx credits within a
NOx trading market.

     In December 2000, having completed its utility study for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is to be developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and regulations are scheduled to be finalized by the end of
2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place around 2010. Litigation of the Regional
Haze Regulations, including the BART provisions, is ongoing in the Federal
District of Columbia Circuit Court of Appeals. A court decision is expected in
mid-2002.

     Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.

     In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.

     The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: control strategies to reduce regional
haze; limits on pollutant discharges to impaired waters; cooling water intake
restrictions; and hazardous waste disposal requirements. The impact of any new
standards will depend on the development and implementation of applicable
regulations.

Environmental Protection Agency Litigation

On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. The civil action requests penalties and injunctive
relief, including an order requiring the installation of the best available
control technology at the affected units. The EPA concurrently issued a notice
of violation to the Company relating to these two plants. In early 2000, the EPA
filed a motion to amend its complaint to add the violations alleged in its
notice of violation. The complaint and the notice of violation are similar to
those brought against and issued to several other electric utilities. The
complaint and the notice of violation allege that the Company failed to secure
necessary permits or install additional pollution control equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. The Company believes that it complied with
applicable laws and the EPA's regulations and interpretations in effect at the


                                     II-90
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day.

    The case against the Company has been stayed since the spring of 2001
pending a ruling by the federal Court of Appeals for the Eleventh Circuit in the
appeal of a very similar Clean Air Act / New Source Review enforcement action
brought by EPA against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on Georgia Power, the Company is a party to that case as well. The
federal court in Georgia is currently considering a motion by the EPA to reopen
the case. The Company has opposed that motion. An adverse outcome of this matter
could require substantial capital expenditures that cannot be determined at this
time and could possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly financial
condition if such costs are not recovered through regulated rates.

Other Environmental Issues

The Company must comply with other environmental laws and regulations that cover
the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. The Company conducts studies to determine the extent of any
required clean-up and has recognized in the financial statements costs to clean
up known sites. These costs for the Company amounted to $0.6 million in 2001 and
$4 million in both 2000 and 1999. Additional sites may require environmental
remediation for which the Company may be liable for all or a portion of required
clean-up costs. See Note 3 to the financial statements under "Other
Environmental Contingencies" for information regarding the Company's potentially
responsible party status at sites in Georgia.

     Several major pieces of environmental legislation are periodically
considered for reauthorization or amendment by Congress. These include: the
Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response,
Compensation, and Liability Act; the Resource Conservation and Recovery Act; the
Toxic Substances Control Act; and the Endangered Species Act. Changes to these
laws could affect many areas of the Company's operations. The full impact of any
such changes cannot be determined at this time.

     Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if any
-- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION

The Company's 2001 Annual Report includes forward-looking statements in addition
to historical information. In some cases, forward-looking statements can be
identified by terminology such as "may," "will," "could," "should," "expects,"
"plans," "anticipates," "believes," "estimates," "predicts," "projects,"
"potential" or "continue" or the negative of these terms or other comparable
terminology. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking statements; accordingly, there can be no assurance that such
indicated results will be realized.
These factors include the impact of recent and future federal and state
regulatory change, including legislative and regulatory initiatives regarding
deregulation and restructuring of the electric utility industry and also changes
in environmental and other laws and regulations to which the Company is subject,
as well as changes in application of existing laws and regulations; current and
future litigation, including the pending EPA civil action and the race
discrimination litigation against the Company; the effect, extent, and timing of
the entry of additional competition in the markets in which the Company
operates; the impact of fluctuations in commodity prices, interest rates, and
customer demand; state and federal rate regulations; political, legal, and
economic conditions and developments in the United States; the effects of, and
changes in economic conditions in the areas in which the Company operates;
internal restructuring or other restructuring options that may be pursued by the
Company; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or


                                       II-91
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2001 Annual Report


beneficial; the direct or indirect effects on the Company's business resulting
from the terrorist incidents on September 11, 2001, or any similar such
incidents or responses to such incidents; financial market conditions and the
results of financing efforts; the ability of the Company to obtain additional
generating capacity at competitive prices; weather and other natural phenomena;
and other factors discussed elsewhere herein and in other reports (including
Form 10-K) filed from time to time by the Company with the Securities and
Exchange Commission.

                                     II-92


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report

-------------------------------------------------------------------------------------------------------------
                                                               2001                 2000                1999
-------------------------------------------------------------------------------------------------------------
                                                                              (in thousands)
Operating Revenues:
<S>                                                      <C>                  <C>                 <C>
Retail sales                                             $4,349,312           $4,317,338          $4,050,088
Sales for resale --
  Non-affiliates                                            366,085              297,643             210,104
  Affiliates                                                 99,411               96,150              76,426
Other revenues                                              150,986              159,487             120,057
-------------------------------------------------------------------------------------------------------------
Total operating revenues                                  4,965,794            4,870,618           4,456,675
-------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel                                                        939,092            1,017,878             919,876
Purchased power --
  Non-affiliates                                            442,196              356,189             214,573
  Affiliates                                                329,232              239,815             174,989
Other                                                       810,043              795,458             784,359
Maintenance                                                 430,413              404,189             411,983
Depreciation and amortization                               600,631              619,094             552,966
Taxes other than income taxes                               202,483              204,527             202,853
-------------------------------------------------------------------------------------------------------------
Total operating expenses                                  3,754,090            3,637,150           3,261,599
-------------------------------------------------------------------------------------------------------------
Operating Income                                          1,211,704            1,233,468           1,195,076
Other Income (Expense):
Interest income                                               4,264                2,629               5,583
Equity in earnings of unconsolidated subsidiaries             4,178                3,051               2,721
Other, net                                                   (2,816)             (50,495)            (47,986)
-------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                 1,217,330            1,188,653           1,155,394
-------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest expense, net                                       183,879              208,868             194,869
Distributions on preferred securities of subsidiaries        59,104               59,104              65,774
-------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                       242,983              267,972             260,643
-------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                974,347              920,681             894,751
Income taxes                                                363,599              360,587             351,639
-------------------------------------------------------------------------------------------------------------
Net Income Before Cumulative Effect of
   Accounting Change                                        610,748              560,094             543,112
Cumulative effect of accounting change --
   less income taxes of $162 thousand                           257               -                   -
-------------------------------------------------------------------------------------------------------------
Net Income                                                  611,005              560,094             543,112
Dividends on Preferred Stock                                    670                  674               1,729
-------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock             $ 610,335            $ 559,420          $  541,383
=============================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>




                                                             II-93



<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report



-------------------------------------------------------------------------------------------------------------------------------
                                                                          2001                  2000                  1999
-------------------------------------------------------------------------------------------------------------------------------
                                                                                            (in thousands)
Operating Activities:
<S>                                                                  <C>                   <C>                   <C>
Net income                                                           $ 611,005             $ 560,094             $ 543,112
Adjustments to reconcile net income to net
     cash provided from operating activities --
         Depreciation and amortization                                 697,143               712,960               663,878
         Deferred income taxes and investment tax credits, net         (48,329)              (28,961)              (34,930)
         Other, net                                                    (92,403)              (51,501)              (42,179)
         Changes in certain current assets and liabilities --
            Receivables, net                                            60,914              (108,621)               21,665
            Fossil fuel stock                                         (103,296)               26,835               (22,165)
            Materials and supplies                                     (15,628)               (9,715)              (10,417)
            Accounts payables                                          (15,406)               64,412                13,095
            Energy cost recovery, retail                               (29,839)              (95,235)              (26,862)
            Other                                                       (2,999)               (9,092)               90,788
-------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                          1,061,162             1,061,176             1,195,985
-------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                            (1,389,751)           (1,078,163)             (790,464)
Sales of property                                                      534,760                     -                     -
Other                                                                   (4,774)               (5,450)              (27,454)
-------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                (859,765)           (1,083,613)             (817,918)
-------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase in notes payable, net                                          43,698                67,598               295,389
Proceeds --
     Senior notes                                                      600,000               300,000               100,000
     Pollution control bonds                                           404,535                78,725               238,000
     Preferred securities                                                    -                     -               200,000
     Capital contributions from parent company                         225,060               301,514               155,777
Retirements --
     First mortgage bonds                                             (390,140)             (100,000)             (404,000)
     Pollution control bonds                                          (385,035)              (78,725)             (235,000)
     Preferred securities                                                    -                     -              (100,000)
     Preferred stock                                                         -                  (383)              (36,231)
Capital distributions to parent company                               (160,000)                    -                     -
Payment of preferred stock dividends                                      (578)                 (751)                 (984)
Payment of common stock dividends                                     (527,300)             (549,600)             (543,000)
Other                                                                  (17,747)               (1,231)              (29,630)
-----------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities                (207,507)               17,147              (359,679)
-----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                 (6,110)               (5,290)               18,388
Cash and Cash Equivalents at Beginning of Year                          29,370                34,660                16,272
-----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                               $23,260               $29,370               $34,660
-----------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
     Interest (net of amount capitalized)                            $ 234,456             $ 265,373             $ 247,050
     Income taxes (net of refunds)                                     381,995               392,310               394,457
-----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>



                                                             II-94


<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report

------------------------------------------------------------------------------------------------------------------
Assets                                                                           2001                     2000
------------------------------------------------------------------------------------------------------------------
                                                                                        (in thousands)
Current Assets:
<S>                                                                          <C>                      <C>
Cash and cash equivalents                                                    $ 23,260                 $ 29,370
Receivables --
  Customer accounts receivable                                                376,322                  465,249
  Underrecovered retail fuel clause revenue                                   161,462                  131,623
  Other accounts and notes receivable                                         129,073                  156,143
  Affiliated companies                                                         87,786                   13,312
Accumulated provision for uncollectible accounts                               (8,895)                  (5,100)
Fossil fuel stock, at average cost                                            202,759                   99,463
Materials and supplies, at average cost                                       279,237                  263,609
Other                                                                         125,246                   97,515
------------------------------------------------------------------------------------------------------------------
Total current assets                                                        1,376,250                1,251,184
------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service                                                                 16,886,399               16,469,706
Less accumulated provision for depreciation                                 7,243,209                6,914,512
------------------------------------------------------------------------------------------------------------------
                                                                            9,643,190                9,555,194
Nuclear fuel, at amortized cost                                               112,771                  120,570
Construction work in progress (Note 4)                                        883,285                  652,264
------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                       10,639,246               10,328,028
------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4)                     35,209                   29,569
Nuclear decommissioning trusts                                                364,180                  375,666
Other                                                                          29,618                   29,745
------------------------------------------------------------------------------------------------------------------
Total other property and investments                                          429,007                  434,980
------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8)                             543,584                  565,982
Prepaid pension costs                                                         228,259                  147,271
Debt expense, being amortized                                                  58,165                   53,748
Premium on reacquired debt, being amortized                                   173,724                  173,610
Other                                                                         117,706                  120,964
------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                     1,121,438                1,061,575
------------------------------------------------------------------------------------------------------------------
Total Assets                                                              $13,565,941              $13,075,767
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>





                                                              II-95


<PAGE>
<TABLE>
<CAPTION>

BALANCE SHEETS
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report

--------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                               2001                     2000
--------------------------------------------------------------------------------------------------------------------
                                                                                          (in thousands)
Current Liabilities:
<S>                                                                        <C>                      <C>
Securities due within one year (Note 9)                                     $   311,620              $     1,808
Notes payable                                                                   747,537                  703,839
Accounts payable --
  Affiliated                                                                    109,591                  117,168
  Other                                                                         409,253                  397,550
Customer deposits                                                                83,172                   78,540
Taxes accrued --
  Income taxes                                                                   35,247                    5,151
  Other                                                                         125,807                  137,511
Interest accrued                                                                 46,942                   47,244
Vacation pay accrued                                                             41,830                   38,865
Other                                                                           112,686                  137,565
--------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                     2,023,685                1,665,241
--------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                  2,961,726                3,041,939
--------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8)                                    2,163,959                2,182,783
Deferred credits related to income taxes (Note 8)                               229,216                  247,067
Accumulated deferred investment tax credits (Note 8)                            337,482                  352,282
Employee benefits provisions                                                    207,795                  191,587
Other                                                                           440,774                  341,505
--------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                  3,379,226                3,315,224
--------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
  securities of subsidiary trusts holding company junior
  subordinated notes (See accompanying statements)                              789,250                  789,250
--------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements)                         14,569                   14,569
--------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                     4,397,485                4,249,544
--------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                  $13,565,941              $13,075,767
====================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>






                                                               II-96


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report


-----------------------------------------------------------------------------------------------------------------------------------
                                                                                   2001               2000           2001    2000
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                       (in thousands)           (percent of total)

Long-Term Debt:
First mortgage bonds

Maturity                         Interest Rates
--------                         -------------
<S>                            <C>                                       <C>                <C>                   <C>         <C>
April 1, 2003                    6.625%                                    $       -          $     200,000
August 1, 2003                   6.35%                                             -                 75,000
2005                             6.07%                                             1,860             10,000
2008                             6.875%                                            -                 50,000
2025                             7.70%                                             -                 57,000
--------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                                         1,860            392,000
--------------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
  Variable rate (1.98125% at 1/1/02) due February 22, 2002                       300,000            300,000
  5.75% due January 31, 2003                                                     200,000              -
  5.25% due May 8, 2003                                                          150,000              -
  5.50% due December 1, 2005                                                     150,000            150,000
  6.20% due February 1, 2006                                                     150,000              -
  6.70% due March 1, 2011                                                        100,000              -
  6.60% due December 31, 2038                                                    200,000            200,000
  6.625% due March 31, 2039                                                      100,000            100,000
  6.875% due December 31, 2047                                                   145,000            145,000
--------------------------------------------------------------------------------------------------------------
Total senior notes payable                                                     1,495,000            895,000
--------------------------------------------------------------------------------------------------------------
Other long-term debt -- (Note 9)
  Pollution control revenue bonds --
  Maturity                         Interest Rates
  -------                          -------------
  2005                             5.00%                                           -                 57,000
  2011                             Variable (1.90% to 1.95% at 1/1/02)            10,450             10,450
  2012-2016                        4.20% to 5.00%                                164,590              -
  2018-2021                        6.00% to 6.25%                                  7,800             23,225
  2018                             Variable (2.00% at 1/1/02)                     19,500             -
  2023-2025                        4.90% to 6.75%                                 28,065            298,535
  2022-2026                        Variable (1.75% to 1.95% at 1/1/02)           669,480            683,555
  2029                             Variable (1.90% to 1.95% at 1/1/02)           144,700            144,700
  2030-2031                        4.53% to 5.25%                                137,570             78,725
  2032-2034                        Variable (1.75% to 1.95% at 1/1/02)           140,000            140,000
  2032-2034                        4.45% to 5.45%                                371,535            238,000
--------------------------------------------------------------------------------------------------------------
Total other long-term debt                                                     1,693,690          1,674,190
--------------------------------------------------------------------------------------------------------------
Capital lease obligations (Note 9)                                                83,371             85,179
--------------------------------------------------------------------------------------------------------------
Unamortized debt discount, net                                                      (575)            (2,622)
--------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest)
   requirement -- $139.5 million)                                              3,273,346          3,043,747
Less amount due within one year (Note ()                                         311,620              1,808
-----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year                  $   2,961,726      $   3,041,939          36.3 %  37.6 %
-----------------------------------------------------------------------------------------------------------------------------------

</TABLE>
                                                              II-97

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Georgia Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------------------
                                                                           2001               2000              2001        2000
-----------------------------------------------------------------------------------------------------------------------------------
                                                                                 (in thousands)                (percent of total)
Company Obligated Mandatorily
   Redeemable Preferred Securities (Note 9):
     <S>                                                                <C>                 <C>                <C>           <C>
     $25 liquidation value -- 6.85%                                      $   200,000        $   200,000
     $25 liquidation value -- 7.60%                                          175,000            175,000
     $25 liquidation value -- 7.75%                                          189,250            189,250
     $25 liquidation value -- 7.75%                                          225,000            225,000
-----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59.1 million)                     789,250            789,250          9.6         9.7
-----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
     Authorized -- 55,000,000 shares
     Outstanding -- 145,689 shares at December 31, 2001
     Outstanding -- 145,689 shares at December 31, 2000
         $100 stated value --
            4.60%                                                             14,569             14,569
-----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
     requirement -- $0.7 million)                                             14,569             14,569          0.2         0.2
-----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
     Authorized -- 15,000,000 shares
     Outstanding --  7,761,500 shares                                        344,250            344,250
Paid-in capital                                                            2,182,557          2,117,497
Premium on preferred stock                                                        40                 40
Other comprehensive income                                                      (153)           -
Retained earnings (Note 9)                                                 1,870,791          1,787,757
-----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statements)            4,397,485          4,249,544         53.9        52.5
-----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                                     $ 8,163,030        $ 8,095,302        100.0 %     100.0 %
-----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.


</TABLE>



                                                              II-98


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report

-------------------------------------------------------------------------------------------------------------------------

                                                                           Premium on                        Other
                                                    Common         Paid-In  Preferred      Retained      Comprehensive
                                                    Stock          Capital    Stock        Earnings      Income (Loss)   Total
------------------------------------------------------------------------------------------------------------------------------

<S>                                              <C>           <C>            <C>       <C>             <C>        <C>
Balance at January 1, 1999                       $344,250      $1,660,206     $158      $1,779,558         $ -      $3,784,172
Net income after dividends on preferred stock           -               -        -         541,383           -         541,383
Capital contributions from parent company               -         155,777        -               -           -         155,777
Cash dividends on common stock                          -               -        -        (543,000)          -        (543,000)
Preferred stock transactions, net                       -               -     (118)             (4)          -            (122)
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                      344,250       1,815,983       40       1,777,937           -       3,938,210
Net income after dividends on preferred stock           -               -        -         559,420           -         559,420
Capital contributions from parent company               -         301,514        -               -           -         301,514
Cash dividends on common stock                          -               -        -        (549,600)          -        (549,600)
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000                      344,250       2,117,497       40       1,787,757           -       4,249,544
Net income after dividends on preferred stock           -               -        -         610,335           -         610,335
Capital contributions from parent company               -         225,060        -               -           -         225,060
Capital distributions to parent company                          (160,000)                                            (160,000)
Other comprehensive income                              -               -        -               -        (153)           (153)
Cash dividends on common stock                          -               -        -        (527,300)          -        (527,300)
Preferred stock transactions, net                       -               -        -              (1)          -              (1)
-------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001                     $344,250      $2,182,557      $40      $1,870,791       ($153)     $4,397,485
===============================================================================================================================
</TABLE>




<TABLE>
<CAPTION>
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Georgia Power Company 2001 Annual Report

---------------------------------------------------------------------------------------------------------------------------
                                                                2001                          2000                    1999
---------------------------------------------------------------------------------------------------------------------------
                                                              (in thousands)

<S>                                                        <C>                           <C>                     <C>
Net income after dividends on preferred stock              $ 610,335                     $ 559,420               $ 541,383
Other comprehensive income:
     Cumulative effect of accounting change, net of tax          286                       -                     -
     Current period changes in fair value, net of tax           (439)                      -                     -
---------------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                       $ 610,182                     $ 559,420               $ 541,383
===========================================================================================================================
The accompanying notes are an integral part of these statements.


</TABLE>

                                                               II-99


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2001 Annual Report


1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, a system service company (SCS),
Southern Communications Services (Southern LINC), Southern Nuclear Operating
Company (Southern Nuclear), Southern Power Company (Southern Power), and other
direct and indirect subsidiaries. The operating companies --Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company-- provide electric service in four
southeastern states. Contracts among the operating companies -- related to
jointly owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission. SCS provides,
at cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Power was established in 2001 to construct, own, and manage Southern
Company's competitive generation assets and sell electricity at market-based
rates in the wholesale market.

     Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows accounting principles generally accepted
in the United States and complies with the accounting policies and practices
prescribed by the respective regulatory commissions. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States requires the use of estimates, and the actual results may
differ from these estimates.

     Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $285 million, $269
million, and $253 million during 2001, 2000, and 1999, respectively.

     The Company has an agreement with Southern Nuclear under which the
following nuclear-related services are rendered to the Company at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting and
statistical, employee relations, and systems and procedures services; strategic
planning and budgeting services; and other services with respect to business and
operations. Costs for these services amounted to $281 million in both 2001 and
2000 and $270 million in 1999.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues associated with
certain costs that are expected to be recovered from customers through the
ratemaking process. Regulatory liabilities represent probable future reductions
in revenues associated with amounts that are expected to be credited to
customers through the ratemaking process. See Note 3 under "Retail Rate Orders"
for additional information regarding the disposition of the regulatory liability
for the accelerated cost recovery recorded under the retail rate order that
ended December 31, 2001. Regulatory assets and (liabilities) reflected in the
Company's Balance Sheets at December 31 relate to the following:



                                      II-100
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report

                                              2001      2000
                                           ----------------------
                                               (in millions)
Deferred income taxes                      $   544    $   566
Deferred income tax credits                   (229)      (247)
Premium on reacquired debt                     174        174
Corporate building lease                        54         55
Vacation pay                                    52         49
Postretirement benefits                         28         30
Department of Energy assessments                18         21
Deferred nuclear outage costs                   24         28
Accelerated cost recovery and
    interest                                  (336)      (230)
Other, net                                      16         23
 --------------------------------------------------------------
Total                                      $   345    $   469
===============================================================

     In the event that a portion of the Company's operations is no longer
subject to the provisions of Statement No. 71, the Company would be required to
write off related regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.

Revenues and Fuel Costs

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Georgia, and to wholesale customers in the Southeast.

     The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts averaged less than 1 percent of revenues.

     Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is
used. The Company's fuel cost recovery mechanism includes provisions to adjust
billings for fluctuations in fuel costs, the energy component of purchased power
costs, and certain other costs. Revenues are adjusted for differences between
recoverable fuel costs and amounts actually recovered in current rates.

     Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $75
million in each of 2001 and 2000 and $74 million in 1999. The Company has
contracts with the U.S. Department of Energy (DOE) that provide for the
permanent disposal of used nuclear fuel. The DOE failed to begin disposing of
used nuclear fuel in January 1998 as required by the contracts, and the Company
is pursuing legal remedies against the government for breach of contract.
Sufficient pool storage capacity is available at Plant Vogtle to maintain
full-core discharge capability for both units until the year 2014. To maintain
pool discharge capability at Plant Hatch, effective June 2000, an on-site dry
storage facility for Plant Hatch became operational. Sufficient dry storage
capacity is believed to be available to continue dry storage operations at Plant
Hatch through the life of the plant. Procurement of on-site dry storage capacity
at Plant Vogtle will commence in sufficient time to maintain pool full-core
discharge capability.

     Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is to be funded in
part by a special assessment on utilities with nuclear plants. The assessment
will be paid over a 15-year period, which began in 1993. This fund will be used
by the DOE for the decontamination and decommissioning of its nuclear fuel
enrichment facilities. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. The Company -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 2001 to be approximately $16 million. This obligation is recorded
in the accompanying Balance Sheets.

Depreciation and Nuclear Decommissioning

Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.3 percent in 2001, 2000, and 1999. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its original
cost -- together with the cost of removal, less salvage -- is charged to
accumulated depreciation. Minor items of property included in the original cost
of the plant are retired when the related property unit is retired. Depreciation
expense includes an amount for the expected costs of decommissioning nuclear
facilities and removal of other facilities.

     Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial power reactors to establish a plan for providing, with


                                      II-101
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


reasonable assurance, funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Earnings on the trust
funds are considered in determining decommissioning expense. The NRC's minimum
external funding requirements are based on a generic estimate of the cost to
decommission the radioactive portions of a nuclear unit based on the size and
type of reactor. The Company has filed plans with the NRC to ensure that -- over
time -- the deposits and earnings of the external trust funds will provide the
minimum funding amounts prescribed by the NRC.

     The Company periodically conducts site-specific studies to estimate the
actual cost of decommissioning its nuclear generating facilities. Site study
cost is the estimate to decommission the facility as of the site study year, and
ultimate cost is the estimate to decommission the facility as of its retirement
date. The estimated site study costs based on the most current study and
ultimate costs assuming an inflation rate of 4.7 percent for the Company's
ownership interests are as follows:

                                           Plant     Plant
                                           Hatch     Vogtle
                                         --------------------
Site study basis (year)                      2000      2000

Decommissioning periods:
   Beginning year                            2014      2027
   Completion year                           2042      2045
-------------------------------------------------------------
                                            (in millions)
Site study costs:
   Radiated structures                       $486      $420
   Non-radiated structures                     37        48
-------------------------------------------------------------
Total                                        $523      $468
=============================================================
                                            (in millions)
Ultimate costs:
   Radiated structures                     $1,004    $1,468
   Non-radiated structures                     79       166
-------------------------------------------------------------
Total                                      $1,083    $1,634
=============================================================

     The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in the NRC requirements, changes in the assumptions
used in making the estimates, changes in regulatory requirements, changes in
technology, and changes in costs of labor, materials, and equipment.

     Annual provisions for nuclear decommissioning expense are based on an
annuity method as approved by the GPSC. The amounts expensed in 2001 and fund
balances as of December 31, 2001 were:


                                              Plant      Plant
                                              Hatch      Vogtle
----------------------------------------------------------------
                                              (in millions)
  Amount expensed in 2001                      $20         $9
================================================================
                                              (in millions)
  Accumulated provisions:
   External trust funds, at fair value        $229       $135
   Internal reserves                            20         12
----------------------------------------------------------------
  Total                                       $249       $147
================================================================

     Effective January 1, 2002, the GPSC decreased the annual provision for
decommissioning expenses to $8 million. This amount is based on the NRC generic
estimate to decommission the radioactive portion of the facilities as of 2000
of $383 million and $282 million for Plants Hatch and Vogtle, respectively. The
ultimate costs associated with the 2000 NRC minimum funding requirements are
$823 million and $1.03 billion for Plants Hatch and Vogtle, respectively.
Significant assumptions include an estimated inflation rate of 4.7 percent and
an estimated trust earnings rate of 6.5 percent. The Company expects the GPSC
to periodically review and adjust, if necessary, the amounts collected in rates
for the anticipated cost of decommissioning.

    In January 2002, the NRC granted the Company a 20-year extension of the
licenses for both units at Plant Hatch which permits the operation of units 1
and 2 until 2034 and 2038, respectively. The decommissioning costs disclosed
above do not reflect this extension.

Income Taxes

The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.

Allowance for Funds Used During Construction
(AFUDC)

AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new regulated facilities. While cash is


                                     II-102
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


not realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. For the years 2001, 2000, and 1999, the average AFUDC
rates were 6.33 percent, 6.74 percent, and 5.61 percent, respectively. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 3.0 percent for 2001, 2000, and 1999.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost, less regulatory
disallowances and impairments. Original cost includes: materials; labor;
payroll-related costs such as taxes, pensions, and other benefits; and the cost
of funds used during construction. The cost of maintenance, repairs, and
replacement of minor items of property is charged to maintenance expense. The
cost of replacements of property (exclusive of minor items of property) is
capitalized.

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.

Comprehensive Income

Comprehensive income -- consisting of net income and changes in the fair value
of qualifying cash flow hedges, net of income taxes -- is presented in the
financial statements. The objective of comprehensive income is to report a
measure of all changes in common stock equity of an enterprise that result from
transactions and other economic events of the period other than transactions
with owners.

Financial Instruments

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on net
income was immaterial.

   The Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, and certain
commodity prices. Gains and losses on qualifying hedges are deferred and
recognized either in income or as an adjustment to the carrying amount of the
hedged item when the transaction occurs.

     The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.

   The Company and its affiliates, through SCS acting as their agent, enter into
commodity related forward and option contracts to limit exposure to changing
prices on certain fuel purchases and electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales contracts
meet the definition of a derivative under Statement No. 133. In many cases,
these fuel and electricity contracts qualify for normal purchase and sale
exceptions under Statement No. 133 and are accounted for under the accrual
method. Other contracts qualify as cash flow hedges of anticipated transactions,
resulting in the deferral of related gains and losses, and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.

     The Company's financial instruments for which the carrying amounts did not
approximate fair value at December 31 were as follows:

                                        Carrying      Fair
                                         Amount       Value
                                      ------------------------
Long-term debt:                             (in millions)
  At December 31, 2001                    $3,190      $3,190
  At December 31, 2000                    $2,959      $2,912
Preferred securities:
  At December 31, 2001                      $789        $782
  At December 31, 2000                      $789        $761
--------------------------------------------------- ----------

     The fair values for securities were based on either closing market prices
or closing prices of comparable instruments.

Materials and Supplies

Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory

                                     II-103
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


when purchased and then expensed or capitalized to plant, as appropriate, when
installed.

2.  RETIREMENT BENEFITS

The Company has defined benefit, trusteed pension plans that cover substantially
all employees. The Company provides certain medical care and life insurance
benefits for retired employees. Substantially all these employees may become
eligible for such benefits when they retire. The Company funds postretirement
trusts to the extent required by the GPSC and the FERC. In late 2000, the
Company adopted several pension and postretirement benefits plan changes that
had the effect of increasing benefits to both current and future retirees. The
measurement date for plan assets and obligations is September 30 of each year.

     The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:

                                                2001      2000
-----------------------------------------------------------------
Discount                                       7.50%      7.50%
Annual salary increase                         5.00       5.00
Expected long-term return on plan
  assets                                       8.50       8.50
-----------------------------------------------------------------

Pension Plan

Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:

                                             Projected
                                        Benefit Obligations
                                     --------------------------
                                         2001          2000
---------------------------------------------------------------
                                           (in millions)
Balance at beginning of year             $1,322        $1,275
Service cost                                 35            32
Interest cost                               101            94
Benefits paid                               (74)          (67)
Actuarial gain and
   employee transfers                        64           (12)
---------------------------------------------------------------
Balance at end of year                   $1,448        $1,322
===============================================================

                                            Plan Assets
                                     ---------------------------
                                         2001          2000
----------------------------------------------------------------
                                           (in millions)
Balance at beginning of year             $2,464        $2,107
Actual return on plan assets               (356)          385
Benefits paid                               (62)          (58)
Employee transfers                           (2)           30
----------------------------------------------------------------
Balance at end of year                   $2,044        $2,464
================================================================

     The accrued pension costs recognized in the Balance Sheets
were as follows:
                                              2001       2000
---------------------------------------------------------------
                                              (in millions)
Funded status                                $ 596    $ 1,142
Unrecognized transition obligation             (22)       (26)
Unrecognized prior service cost                 98         44
Unrecognized net actuarial gain               (444)    (1,013)
---------------------------------------------------------------
Prepaid asset recognized in the
      Balance Sheets                         $ 228    $   147
===============================================================

     Components of the plan's net periodic cost were as follows:

                                         2001    2000     1999
---------------------------------------------------------------
                                            (in millions)
Service cost                            $  35   $  33    $  33
Interest cost                             101      94       86
Expected return on plan assets           (168)   (152)    (137)
Recognized net actuarial gain             (31)    (26)     (17)
Net amortization                            3      (1)       -
---------------------------------------------------------------
Net pension income                      $ (60)  $ (52)   $ (35)
===============================================================

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:

                                            Accumulated
                                         Benefit Obligations
                                     -------------------------
                                          2001          2000
--------------------------------------------------------------
                                           (in millions)
Balance at beginning of year              $495          $438
Service cost                                 9             7
Interest cost                               39            36
Benefits paid                              (24)          (21)
Actuarial gain and
   employee transfers                       23            35
--------------------------------------------------------------
Balance at end of year                    $542          $495
==============================================================


                                     II-104
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report

                                            Plan Assets
                                     ---------------------------
                                          2001          2000
----------------------------------------------------------------
                                           (in millions)
Balance at beginning of year              $198          $177
Actual return on plan assets               (26)           12
Employer contributions                      47            30
Benefits paid                              (24)          (21)
----------------------------------------------------------------
Balance at end of year                    $195          $198
================================================================

    The accrued postretirement costs recognized in the Balance Sheets were as
follows:

                                             2001      2000
---------------------------------------------------------------
                                              (in millions)
Funded status                                $(347)     $(297)
Unrecognized transition obligation             105        113
Unrecognized prior service cost                104         60
Unrecognized (gain)/loss                         5        (13)
Fourth quarter contributions                    27         27
---------------------------------------------------------------
Accrued liability recognized in the
      Balance Sheets                         $(106)     $(110)
===============================================================

    Components of the plans' net periodic cost were as follows:

                                         2001   2000     1999
---------------------------------------------------------------
                                            (in millions)
Service cost                             $  9   $  7      $ 8
Interest cost                              39     36       30
Expected return on plan assets            (19)   (16)     (10)
Recognized net actuarial loss               -      -        1
Net amortization                           14     12        9
---------------------------------------------------------------
Net postretirement cost                  $ 43   $ 39      $38
===============================================================

      An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:

                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
                                           (in millions)
Benefit obligation                       $54         $46
Service and interest costs                 5           4
===============================================================

Employee Savings Plan

The Company sponsors a 401(k) defined contribution plan covering substantially
all employees. The Company provides a 75 percent matching contribution up to 6
percent of an employee's base salary. Total matching contributions made to the
plan for the years 2001, 2000, and 1999 were $16 million, $15 million, and $15
million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General

The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.

Retail Rate Orders

On December 20, 2001, the GPSC approved a new three-year retail rate order for
the Company ending December 31, 2004. Under the terms of the order, earnings
will be evaluated against a retail return on common equity range of 10 percent
to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will
be applied to rate refunds, with the remaining one-third retained by the
Company. Retail rates were decreased by $118 million effective January 1, 2002.

    Under a previous three-year order ending December 2001, the Company's
earnings were evaluated against a retail return on common equity range of 10
percent to 12.5 percent. The order further provided for $85 million in each
year, plus up to $50 million of any earnings above the 12.5 percent return
during the second and third years, to be applied to accelerated amortization or
depreciation of assets. Two-thirds of any additional earnings above the 12.5
percent return were applied to rate refunds, with the remaining one-third
retained by the Company. Pursuant to the order, the Company recorded $336
million of accelerated amortization and interest thereon which has been credited
to a regulatory liability account as mandated by the GPSC.

    Under the new rate order, the accelerated amortization and the interest will
be amortized equally over three years as a credit to expense beginning in 2002.
Effective January 1, 2002, the Company discontinued recording accelerated


                                     II-105
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


depreciation and amortization. The Company will not file for a general base rate
increase unless its projected retail return on common equity falls below 10
percent. Georgia Power is required to file a general rate case on July 1, 2004,
in response to which the GPSC would be expected to determine whether the rate
order should be continued, modified, or discontinued.

    In 2000 and 1999, the Company recorded $44 million and $79 million,
respectively, of revenue subject to refund for estimated earnings above 12.5
percent retail return on common equity. Refunds applicable to 2000 and 1999 were
made to customers in 2001 and 2000, respectively.

Environmental Protection Agency (EPA) Litigation

On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. The civil action requests penalties and injunctive
relief, including an order requiring the installation of the best available
control technology at the affected units beginning at the point of the alleged
violations. The Clean Air Act authorizes civil penalties of up to $27,500 per
day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.

     The EPA concurrently issued a notice of violation to the Company relating
to these two plants. In early 2000, the EPA filed a motion to amend its
complaint to add the violations alleged in its notice of violation. The
complaint and the notice of violation are similar to those brought against and
issued to several other electric utilities. The complaint and the notice of
violation allege that the Company failed to secure necessary permits or install
additional pollution control equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place.

     The case against the Company has been stayed since the spring of 2001
pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
appeal of a very similar Clean Air Act / New Source Review enforcement action
brought by EPA against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against the
Company. Because the outcome of the TVA case could have a significant adverse
impact on Georgia Power, the Company is a party to that case as well. The
federal court in Georgia is currently considering a motion by the EPA to reopen
the Georgia case. The Company has opposed that motion. An adverse outcome of
this matter could require substantial capital expenditures that cannot be
determined at this time and possibly require payment of substantial penalties.
This could affect future results of operations, cash flows, and possibly
financial condition if such costs are not recovered through regulated rates.

Other Environmental Contingencies

The Company has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act. Georgia
Power has recognized $33 million in cumulative expenses through December 31,
2001 for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia that is listed on the federal National Priorities List.
Georgia Power has contributed to the removal and remedial investigation and
feasibility study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated. As of December 31, 2001, Georgia
Power had recorded approximately $6 million in cumulative expenses associated
with Georgia Power's agreed-upon share of the removal and remedial investigation
and feasibility study costs for the Brunswick site.

   The final outcome of these matters cannot now be determined. However, based
on the currently known conditions at these sites and the nature and extent of
Georgia Power's activities relating to these sites, management does not believe
that the Company's cumulative liability at these sites would be material to the
financial statements.

                                     II-106
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


Nuclear Performance Standards

The GPSC has adopted a nuclear performance standard for the Company's nuclear
generating units under which the performance of Plants Hatch and Vogtle is
evaluated every three years. The performance standard is based on each unit's
capacity factor as compared to the average of all comparable U.S. nuclear units
operating at a capacity factor of 50 percent or higher during the three-year
period of evaluation. Depending on the performance of the units, the Company
could receive a monetary award or penalty under the performance standards
criteria.

     The GPSC has approved performance awards of approximately $11.7 million and
$7.8 million for performance during the 1993-1995 period and the 1996-1998
period, respectively. These awards are collected through the retail fuel cost
recovery provision and recognized in income over 36-month periods that began in
January 1997 and 2000, respectively, as mandated by the GPSC.

Race Discrimination Litigation

On July 28, 2000, a lawsuit alleging race discrimination was filed by three
Georgia Power employees against the Company, Southern Company, and SCS in the
United States District Court for the Northern District of Georgia. The lawsuit
also raised claims on behalf of a purported class. The plaintiffs seek
compensatory and punitive damages in an unspecified amount, as well as
injunctive relief. On August 14, 2000, the lawsuit was amended to add four more
plaintiffs. Also, an additional subsidiary of Southern Company, Southern Company
Energy Solutions, Inc., was named a defendant.

    On October 11, 2001, the district court denied plaintiffs' motion for class
certification. The plaintiffs filed a motion to reconsider the order denying
class certification, and the court denied the plaintiffs' motion to reconsider.
On December 28, 2001, the plaintiffs filed a petition in the United States Court
of Appeals for the Eleventh Circuit seeking permission to file an appeal of the
October 11 decision. The defendants filed a brief in opposition of the petition
on January 18, 2002. Discovery of the seven named plaintiffs' individual claims
that remain in the case is ongoing. The final outcome of the case cannot be
determined.

4.  COMMITMENTS

Construction Program

Georgia Power had three new generation projects under construction during 2001.
They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion
turbine facility; two combined cycle units totaling 1,132 megawatts at Plant
Wansley; and Plant Goat Rock, a two-unit, 1,181 megawatt combined cycle
facility. All three of these projects have been transferred to Southern Power
Company, a new Southern Company affiliate formed in 2001 to construct, own, and
manage wholesale generating assets in the Southeast. The ten Dahlberg units and
two Goat Rock units were transferred in 2001 and the transfer of the two Wansley
units was completed in January 2002. Significant construction of transmission
and distribution facilities and projects to remain in compliance with
environmental requirements will continue. The Company currently estimates
property additions to be approximately $1.0 billion in 2002, $0.8 billion in
2003, and $0.8 billion in 2004.

    In connection with the transfer of Plants Dahlberg, Goat Rock, and Wansley,
the Company has assigned $61 million in vendor equipment contracts to Southern
Power. While the Company could be obligated to assume responsibility for these
contracts if Southern Power fails to meet these commitments, Southern Company
has entered into limited keep-well arrangements whereby Southern Company would
contribute funds to Southern Power either through loans or capital
contributions in order to fund performance by Southern Power as equipment
purchaser under certain contingencies.  Southern Company has also guaranteed
Southern Power obligations totaling $6.6 milion for the Company's construction
of transmission interconnection facilities to these plants.

     The construction program is subject to periodic review and revision, and
actual construction costs may vary from estimates because of numerous factors,
including, but not limited to, changes in business conditions, load growth
estimates, environmental regulations, and regulatory requirements.

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels, and other financial commitments.


                                      II-107
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


Total estimated long-term fossil and nuclear fuel commitments at December 31,
2001 were as follows:

                                                 Minimum
Year                                           Obligations
----                                      -------------------
                                              (in millions)
2002                                              $1,234
2003                                               1,115
2004                                                 617
2005                                                 527
2006                                                 521
2007 and beyond                                    1,857
-------------------------------------------------------------
Total                                             $5,871
=============================================================

     Additional commitments for coal and for nuclear fuel will be required in
the future to supply the Company's fuel needs.

     In addition, SCS acts as agent for the five operating companies and
Southern Power with regard to natural gas purchases. Natural gas purchases (in
dollars) are based on various indices at the actual time of delivery; therefore,
only the volume commitments are firm and disclosed in the following chart. The
committed volumes, as of December 31, 2001 are as follows:

Year                                             Natural Gas
----                                         ------------------
                                                  (MMBtu)
2002                                             18,927,055
2003                                             30,434,645
2004                                             30,352,580
2005                                             23,050,128
2006                                             20,038,214
2007 and beyond                                   7,153,129
---------------------------------------------------------------
Total                                           129,955,751
===============================================================

Purchased Power Commitments

The Company and an affiliate, Alabama Power, own equally all of the outstanding
capital stock of Southern Electric Generating Company (SEGCO), which owns
electric generating units with a total rated capacity of 1,020 megawatts, as
well as associated transmission facilities. The capacity of the units has been
sold equally to the Company and Alabama Power under a contract which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, debt service, and return on investment, whether or not SEGCO has any
capacity and energy available. The term of the contract extends automatically
for two-year periods, subject to either party's right to cancel upon two year's
notice. The Company's share of expenses included in purchased power from
affiliates in the Statements of Income is as follows:

                                2001        2000       1999
                             ---------------------------------
                                     (in millions)
Energy                           $52         $57        $51
Capacity                          30          30         29
--------------------------------------------------------------
Total                            $82         $87        $80
==============================================================

    The Company has commitments regarding a portion of a 5 percent interest in
Plant Vogtle owned by Municipal Electric Authority of Georgia (MEAG) that are in
effect until the latter of the retirement of the plant or the latest stated
maturity date of MEAG's bonds issued to finance such ownership interest. The
payments for capacity are required whether or not any capacity is available. The
energy cost is a function of each unit's variable operating costs. Except as
noted below, the cost of such capacity and energy is included in purchased power
from non-affiliates in the Company's Statements of Income. Capacity payments
totaled $59 million, $58 million, and $57 million in 2001, 2000, and 1999,
respectively. The current projected Plant Vogtle capacity payments are:

Year                                         Capacity Payments
                                          ----------------------
                                              (in millions)
2002                                                $ 58
2003                                                  59
2004                                                  55
2005                                                  55
2006                                                  55
2007 and beyond                                      483
----------------------------------------------------------------
Total                                               $765
================================================================

    Portions of the payments noted above relate to costs in excess of Plant
Vogtle's allowed investment for ratemaking purposes. The present value of these
portions was written off in 1987 and 1990.

                                     II-108
<PAGE>

NOTES (continued)
Georgia Power Company 2001 Annual Report


     The Company has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
2001 were as follows:

Year                                                  Non-
                                 Affiliated        Affiliated
----                          --------------------------------
                                       (in millions)
2002                              $   66            $ 39
2003                                 123              41
2004                                 183              40
2005                                 198              40
2006                                 197              40
2007 and beyond                    1,138             396
------------------------------------------------------------
Total                             $1,905            $596
============================================================

Operating Leases

The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $14 million for 2001, $16 million
for 2000, and $11 million for 1999. At December 31, 2001, estimated minimum
rental commitments for these noncancelable operating leases were as follows:

Year                                      Minimum Obligations
                                       -----------------------
                                             (in millions)
2002                                             $ 15
2003                                               15
2004                                               15
2005                                               15
2006                                               15
2007 and beyond                                    91
--------------------------------------------------------------
Total                                            $166
==============================================================

   In addition to the rental commitments above, the Company has obligations upon
expiration of certain of the rail car leases with respect to the residual value
of the leased property. These leases expire in 2004 and 2010, and the Company's
maximum obligations are $13 million and $40 million, respectively. At the
termination of the leases, at the Company's option, the Company may either
exercise its purchase option or the property can be sold to a third party. The
Company expects that the fair market value of the leased property would
substantially reduce or eliminate the Company's payments under the residual
value obligation.

5.  NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The Act provides funds up to $9.5 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $200 million by
American Nuclear Insurers (ANI), with the remaining coverage provided by a
mandatory program of deferred premiums that could be assessed, after a nuclear
incident, against all owners of nuclear reactors. The Company could be assessed
up to $88 million per incident for each licensed reactor it operates but not
more than an aggregate of $10 million per incident to be paid in a calendar year
for each reactor. Such maximum assessment for the Company, excluding any
applicable state premium taxes -- based on its ownership and buyback interests
-- is $178 million per incident but not more than an aggregate of $20 million to
be paid for each incident in any one year.

     The Company is a member of Nuclear Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.

     Additionally, the Company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.

     NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years.

     Under each of the NEIL policies, members are subject to assessments if
losses each year exceed the accumulated funds available to the insurer under
that policy. The current maximum annual assessments for the Company under the
three NEIL policies would be $39 million.


                                      II-109
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


    Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200 million in a policy year.

     For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies should be
dedicated first for the sole purpose of placing the reactor in a safe and stable
condition after an accident. Any remaining proceeds are to be applied next
toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the Company or
to its bond trustees as may be appropriate under the policies and applicable
trust indentures.

     All retrospective assessments, whether generated for liability, property,
or replacement power, may be subject to applicable state premium taxes.

6.  JOINT OWNERSHIP AGREEMENTS

Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned generating facilities. The Company jointly owns the Rocky
Mountain pumped storage hydroelectric plant with Oglethorpe Power Company who is
the operator of the plant. The Company also jointly owns Plant McIntosh with
Savannah Electric and Power Company who operates the plant. The Company and
Florida Power Corporation (FPC) jointly own a combustion turbine unit
(Intercession City) operated by FPC.

     The Company includes its proportionate share of plant operating expenses in
the corresponding operating expenses in the Statements of Income.

     At December 31, 2001, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial operation
were as follows:

                               Company                  Accumulated
Facility (Type)               Ownership    Investment   Depreciation
--------------------------------------------------------------------
                                                (in millions)
Plant Vogtle (nuclear)           45.7%      $3,304         $1,793
Plant Hatch (nuclear)            50.1          881            668
Plant Wansley (coal)             53.5          309            152
Plant Scherer (coal)
   Units 1 and 2                  8.4          112             56
   Unit 3                        75.0          545            221
Plant McIntosh
 Common Facilities               75.0           24              2
   (combustion-turbine)
Rocky Mountain                   25.4          169             78
  (pumped storage)
Intercession City                33.3           12              1
  (combustion-turbine)
--------------------------------------------------------------------

7.   LONG-TERM POWER SALES AGREEMENTS

The Company and the other operating companies of Southern Company have long-term
contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. These
agreements consist of firm unit power sales pertaining to capacity from specific
generating units. Because energy is generally sold at cost under these
agreements, it is primarily the capacity revenues that affect the Company's
profitability.

     The Company's capacity revenues were as follows:

               Year      Revenues      Capacity
               ----------------------------------
                      (in millions) (megawatts)
               2001        $  26           102
               2000           30           124
               1999           32           162
               ----------------------------------

     Unit power from specific generating plants is being sold to Florida Power &
Light Company, FPC, and Jacksonville Electric Authority. Under these agreements,
approximately 102 megawatts of capacity is scheduled to be sold annually for
periods after 2001 with a minimum of three years notice until the expiration of
the contracts in 2010.

8.  INCOME TAXES

At December 31, 2001, tax-related regulatory assets were $544 million and
tax-related regulatory liabilities were $229 million. The assets are


                                     II-110
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized interest. The liabilities are attributable to
deferred taxes previously recognized at rates higher than current enacted tax
law and to unamortized investment tax credits.

     Details of the federal and state income tax provisions are as follows:

                                    2001       2000      1999
                                  ----------------------------
Total provision for income taxes:        (in millions)
Federal:
   Current                          $352       $342      $333
   Deferred                          (46)       (34)      (34)
--------------------------------------------------------------
                                     306        308       299
--------------------------------------------------------------
State:
   Current                            61         48        54
   Deferred                           (8)        (5)       (6)
   Deferred investment tax
     credits                           5         10         5
--------------------------------------------------------------
Total                               $364       $361      $352
==============================================================

     The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:

                                                  2001      2000
                                              -------------------
                                                   (in millions)
Deferred tax liabilities:
   Accelerated depreciation                     $1,722    $1,755
   Property basis differences                      660       683
   Other                                           295       243
-----------------------------------------------------------------
Total                                            2,677     2,681
-----------------------------------------------------------------
Deferred tax assets:
   Other property basis differences                178       189
   Federal effect of state deferred taxes           88        91
   Other deferred costs                            257       208
   Other                                            40        37
-----------------------------------------------------------------
Total                                              563       525
-----------------------------------------------------------------
Net deferred tax liabilities                     2,114     2,156
Portion included in current assets                  50        27
-----------------------------------------------------------------
Accumulated deferred income taxes
   in the Balance Sheets                        $2,164    $2,183
=================================================================

     Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $15 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.

     A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:

                                      2001     2000     1999
                                     -------------------------
Federal statutory rate                  35%      35%      35%
State income tax, net of
   federal deduction                     4        4        4
Non-deductible book
   depreciation                          2        2        2
Other                                   (4)      (2)      (2)
--------------------------------------------------------------
Effective income tax rate               37%      39%      39%
==============================================================

     Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.

9.  CAPITALIZATION

First Mortgage Bond Indenture Restrictions

The Company's first mortgage bond indenture contains various restrictions that
remain in effect as long as the bonds are outstanding. However, the Company
expects to discharge its first mortgage bond indenture by spring 2002 and to be
released from all indenture requirements. At December 31, 2001, $1.037 billion
of retained earnings and paid-in capital was unrestricted for the payment of
cash dividends or any other distributions under terms of the mortgage indenture.
The Company has no restrictions on the amount of indebtedness it may incur.

Preferred Securities

Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:

              Date of                                 Maturity
               Issue      Amount   Rate      Notes      Date
             ---------------------------------------------------
                       (millions)           (millions)
Trust I       8/1996      $225.00  7.75%     $232      6/2036
Trust II      1/1997       175.00  7.60       180     12/2036
Trust III     6/1997       189.25  7.75       195      3/2037
Trust IV      2/1999       200.00  6.85       206      3/2029


                                     II-111
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


     Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above.

     The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.

     The Trusts are subsidiaries of the Company, and accordingly are
consolidated in the Company's financial statements.

Pollution Control Bonds

The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The Company has
authenticated and delivered to trustees an aggregate of $7.8 million of its
first mortgage bonds outstanding at December 31, 2001, which are pledged as
security for its obligations under pollution control revenue contracts. The
redemption of these securities will occur in March 2002.

Senior Notes

In February 2000, February 2001, and May 2001, the Company issued unsecured
senior notes. The proceeds of these issues were used to redeem higher cost
long-term debt and to reduce short-term borrowing. The senior notes are, in
effect, subordinated to all secured debt of the Company.

Bank Credit Arrangements

At the beginning of 2002, the Company had unused credit arrangements with banks
totaling $1.8 billion, of which $1.3 billion expires at various times during
2002 and $500 million expires at April 24, 2003.

     Of the total $1.8 billion in unused credit, $1.65 billion is a syndicated
credit arrangement with $1.15 billion expiring April 19, 2002 and $500 million
expiring April 24, 2003. Upon expiration, the $1.15 billion agreement provides
the option of converting borrowings into two-year term loans. Both agreements
contain stated borrowing rates but also allow for competitive bid loans. In
addition, the agreements require payment of commitment fees based on the unused
portions of the commitments. Annual fees are also paid to the agent bank.

     Approximately $115 million of the $1.3 billion arrangements expiring during
2002 allow for two-year term loans executable upon the expiration date of the
facilities. All of the arrangements include stated borrowing rates but also
allow for negotiated rates. These agreements also require payment of commitment
fees based on the unused portion of the commitments or the maintenance of
compensating balances with the banks. These balances are not legally restricted
from withdrawal.

     This $1.8 billion in unused credit arrangements provides liquidity support
to the Company's variable rate pollution control bonds. The amount of variable
rate pollution control bonds outstanding requiring that liquidity support as of
December 31, 2001 was $984 million.

     In addition, the Company borrows under uncommitted lines of credit with
banks and through commercial paper programs that has the liquidity support of
committed bank credit arrangements. Average compensating balances held under
these committed facilities were not material in 2001. The amount of commercial
paper outstanding at December 31, 2001 was $707.6 million

Other Long-Term Debt

Assets acquired under capital leases are recorded in the Balance Sheets as
utility plant in service, and the related obligations are classified as
long-term debt. At December 31, 2001 and 2000, the Company had a capitalized
lease obligation for its corporate headquarters building of $83 million with an
interest rate of 8.1 percent. For ratemaking purposes, the GPSC has treated the
lease as an operating lease and has allowed only the lease payments in cost of
service. The difference between the accrued expense and the lease payments
allowed for ratemaking purposes has been deferred and is being amortized to
expense as ordered by the GPSC. At December 31, 2001 and 2000, the interest and
lease amortization deferred on the Balance Sheets are $54 million and $55
million, respectively.

Assets Subject to Lien

The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.



                                     II-112
<PAGE>
NOTES (continued)
Georgia Power Company 2001 Annual Report


Georgia Power expects to discharge its first mortgage bond indenture by spring
2002 and that the lien will be removed.

Securities Due Within One Year

A summary of the improvement fund requirements and scheduled maturities and
redemptions of securities due within one year at December 31 is as follows:

                                                2001     2000
                                             ------------------
                                               (in millions)
Capital lease                                   $  2        $2
First mortgage bonds                               2         -
Pollution control bonds                            8         -
Senior notes                                     300         -
---------------------------------------------------------------
Total                                           $312        $2
===============================================================

     The Company's first mortgage bond indenture includes an improvement fund
requirement that amounts to 1 percent of each outstanding series of bonds
authenticated under the indenture prior to January 1 of each year, other than
those issued to collateralize pollution control obligations. The requirement may
be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. However, the
Company expects to discharge its first mortgage bond indenture by spring 2002
and to be released from all indenture requirements.

     Serial maturities through 2006 applicable to total long-term debt are as
follows: $312 million in 2002; $352 million in 2003; $2 million in 2004; $154
million in 2005; and $153 million in 2006.


10. QUARTERLY FINANCIAL DATA
   (UNAUDITED)

Summarized quarterly financial information for 2001 and 2000 is as follows:


                                                       Net Income
                                                         After
                          Operating     Operating     Dividends on
     Quarter Ended        Revenues       Income      Preferred Stock
---------------------------------------------------------------------
                                        (in millions)
                         --------------------------------------------
March 2001                  $1,108         $249           $108
June 2001                    1,259          322            163
September 2001               1,579          515            298
December 2001                1,020          126             41


March 2000                  $  992         $223           $ 94
June 2000                    1,221          311            148
September 2000               1,545          537            283
December 2000                1,113          162             34
---------------------------------------------------------------------

     The Company's business is influenced by seasonal weather conditions.


                                     II-113
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Georgia Power Company 2001 Annual Report


--------------------------------------------------------------------------------------------------------------------------------
                                                           2001             2000         1999             1998             1997
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>              <C>          <C>              <C>              <C>
Operating Revenues (in thousands)                    $4,965,794       $4,870,618   $4,456,675       $4,738,253       $4,385,717
Net Income after Dividends
  on Preferred Stock (in thousands)                    $610,335         $559,420     $541,383         $570,228         $593,996
Cash Dividends
  on Common Stock (in thousands)                       $527,300         $549,600     $543,000         $536,600         $520,000
Return on Average Common Equity (percent)                 14.12            13.66        14.02            14.61            14.53
Total Assets (in thousands)                         $13,565,941      $13,075,767  $12,361,860      $12,033,618      $12,573,728
Gross Property Additions (in thousands)              $1,389,751       $1,078,163     $790,464         $499,053         $475,921
--------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                  $4,397,485       $4,249,544   $3,938,210       $3,784,172       $4,019,728
Preferred stock                                          14,569           14,569       14,952           15,527          157,247
Company obligated mandatorily
  redeemable preferred securities                       789,250          789,250      789,250          689,250          689,250
Long-term debt                                        2,961,726        3,041,939    2,688,358        2,744,362        2,982,835
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)        $8,163,030       $8,095,302   $7,430,770       $7,233,311       $7,849,060
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                        53.9             52.5         53.0             52.3             51.2
Preferred stock                                             0.2              0.2          0.2              0.2              2.0
Company obligated mandatorily
  redeemable preferred securities                           9.6              9.7         10.6              9.5              8.8
Long-term debt                                             36.3             37.6         36.2             38.0             38.0
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)             100.0            100.0        100.0            100.0            100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
  Moody's                                                    A1               A1           A1               A1               A1
  Standard and Poor's                                         A                A           A+               A+               A+
  Fitch                                                     AA-              AA-          AA-              AA-              AA-
Preferred Stock -
  Moody's                                                  Baa1               a2           a2               a2               a2
  Standard and Poor's                                      BBB+             BBB+           A-                A                A
  Fitch                                                       A                A           A+               A+               A+
Unsecured Long-Term Debt -
  Moody's                                                    A2               A2           A2               A2               A2
  Standard and Poor's                                         A                A            A                A                A
  Fitch                                                      A+               A+           A+               A+               A+
================================================================================================================================
Customers (year-end):
Residential                                           1,698,407        1,669,566    1,632,450        1,596,488        1,561,675
Commercial                                              244,674          237,977      229,524          221,180          211,672
Industrial                                                8,046            8,533        8,958            9,485            9,988
Other                                                     3,239            3,159        3,060            3,034            2,748
--------------------------------------------------------------------------------------------------------------------------------
Total                                                 1,954,366        1,919,235    1,873,992        1,830,187        1,786,083
================================================================================================================================
Employees (year-end):                                     9,048            8,860        8,961            8,371            8,354
--------------------------------------------------------------------------------------------------------------------------------

</TABLE>




                                                             II-114



<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Georgia Power Company 2001 Annual Report


----------------------------------------------------------------------------------------------------------------------------
                                                    2001             2000            1999             1998             1997
----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S>                                          <C>               <C>            <C>              <C>              <C>
Residential                                  $ 1,507,031       $1,535,684     $ 1,410,099      $ 1,486,699      $ 1,326,787
Commercial                                     1,682,918        1,620,466       1,527,880        1,591,363        1,493,353
Industrial                                     1,106,420        1,154,789       1,143,001        1,170,881        1,110,311
Other                                             52,943            6,399         (30,892)          49,274           47,848
----------------------------------------------------------------------------------------------------------------------------
Total retail                                   4,349,312        4,317,338       4,050,088        4,298,217        3,978,299
Sales for resale  - non-affiliates               366,085          297,643         210,104          259,234          282,365
Sales for resale  - affiliates                    99,411           96,150          76,426           81,606           38,708
----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity       4,814,808        4,711,131       4,336,618        4,639,057        4,299,372
Other revenues                                   150,986          159,487         120,057           99,196           86,345
----------------------------------------------------------------------------------------------------------------------------
Total                                         $4,965,794       $4,870,618      $4,456,675       $4,738,253       $4,385,717
============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential                                   20,119,080       20,693,481      19,404,709       19,481,486       17,295,022
Commercial                                    26,493,255       25,628,402      23,715,485       22,861,391       21,134,346
Industrial                                    25,349,477       27,543,265      27,300,355       27,283,147       26,701,685
Other                                            583,007          568,906         551,451          543,462          538,163
----------------------------------------------------------------------------------------------------------------------------
Total retail                                  72,544,819       74,434,054      70,972,000       70,169,486       65,669,216
Sales for resale  - non-affiliates             8,110,096        6,463,723       5,060,931        6,438,891        6,795,300
Sales for resale  - affiliates                 3,133,485        2,435,106       1,795,243        2,038,400        1,706,699
----------------------------------------------------------------------------------------------------------------------------
Total                                         83,788,400       83,332,883      77,828,174       78,646,777       74,171,215
============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                         7.49             7.42            7.27             7.63             7.67
Commercial                                          6.35             6.32            6.44             6.96             7.07
Industrial                                          4.36             4.19            4.19             4.29             4.16
Total retail                                        6.00             5.80            5.71             6.13             6.06
Sales for resale                                    4.14             4.43            4.18             4.02             3.78
Total sales                                         5.75             5.65            5.57             5.90             5.80
Residential Average Annual
  Kilowatt-Hour Use Per Customer                  11,933           12,520          12,006           12,314           11,171
Residential Average Annual
  Revenue Per Customer                           $893.84          $929.11         $872.48          $939.73          $857.01
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                  14,474           15,114          14,474           14,437           14,437
Maximum Peak-Hour Demand (megawatts):
Winter                                            11,977           12,014          11,568           11,959           10,407
Summer                                            14,294           14,930          14,575           13,923           13,153
Annual Load Factor (percent)                        61.7             61.6            58.9             58.7             57.4
Plant Availability (percent):
Fossil-steam                                        88.5             86.1            84.3             86.0             85.8
Nuclear                                             94.4             91.5            89.3             91.6             88.8
----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                58.5             62.3            63.0             62.3             64.3
Nuclear                                             18.1             17.4            18.0             18.3             18.8
Hydro                                                1.1              0.7             0.9              2.2              2.2
Oil and gas                                          0.4              1.8             1.6              2.2              0.6
Purchased power -
  From non-affiliates                                7.8              8.1             6.6              6.5              2.7
  From affiliates                                   14.1              9.7             9.9              8.5             11.4
----------------------------------------------------------------------------------------------------------------------------
Total                                              100.0            100.0           100.0            100.0            100.0
============================================================================================================================

                                                             II-115

</TABLE>




<PAGE>

                               GULF POWER COMPANY
                               FINANCIAL SECTION

                                       II-116


<PAGE>



MANAGEMENT'S REPORT
Gulf Power Company 2001 Annual Report


The management of Gulf Power Company has prepared -- and is responsible for --
the financial statements and related information included in this report. These
statements were prepared in accordance with accounting principles generally
accepted in the United States and necessarily include amounts that are based on
the best estimates and judgments of management. Financial information throughout
this annual report is consistent with the financial statements.

   The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.

   The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.

   The audit committee of the board of directors, composed of five independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.

   Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.

   In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Gulf Power Company in conformity with accounting principles generally
accepted in the United States.


/s/ Travis J. Bowden
Travis J. Bowden
President
and Chief Executive Officer


/s/Ronnie R. Labrato
Ronnie R. Labrato
Vice President, Chief Financial Officer
and Comptroller
February 13, 2002



                                    II-117


<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Gulf Power Company:


We have audited the accompanying balance sheets and statements of capitalization
of Gulf Power Company (a Maine corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 2001 and 2000, and the related statements
of income, common stockholder's equity, and cash flows for each of the three
years in the period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

   We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

   In our opinion, the financial statements (pages II-129 through II-144)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

   As explained in Note 1 to the financial statements, effective January 1,
2001, Gulf Power Company changed its method of accounting for derivative
instruments and hedging activities.



/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002


                                     II-118
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 2001 Annual Report


RESULTS OF OPERATIONS

Earnings

Gulf Power Company's 2001 net income after dividends on preferred stock was
$58.3 million, an increase of $6.5 million from the previous year. In 2000,
earnings were $51.8 million, down $1.9 million when compared to 1999. The
increase in earnings in 2001 was due primarily to an increase in Allowance for
Funds Used During Construction (AFUDC) and lower interest expense; the decrease
in 2000 was primarily a result of expenses related to the discontinuance of the
Company's appliance sales division, and higher interest expense.

Revenues

Operating revenues increased in 2001 when compared to 2000. The following table
summarizes the change in operating revenues for the past two years:

                                             Increase (Decrease)
                               Amount          From Prior Year
                             ------------------------------------
                                  2001        2001         2000
                             ------------------------------------
                                         (in thousands)
Retail --
   Base Revenues              $340,620       $4,517       $3,771
   Regulatory cost
     recovery and other        243,971       31,434       27,920
-----------------------------------------------------------------
Total retail                   584,591       35,951       31,691
------------------------------------------------------ ----------
Sales for resale--
   Non-affiliates               82,252       15,362        4,536
   Affiliates                   27,256      (39,739)         885
-----------------------------------------------------------------
Total sales for resale         109,508      (24,377)       5,421
Other operating
   revenues                     31,104         (690)       3,108
-----------------------------------------------------------------
Total operating
   revenues                  $725,203       $10,884      $40,220
=================================================================
Percent change                               1.5%          6.0%
----------------------------------------------------------------

   Retail revenues increased $36 million, or 6.6 percent in 2001, and $31.7
million or 6.1 percent in 2000, due primarily to the recovery of higher fuel and
purchased power costs. Retail base rate revenues increased $4.5 million due to
slightly higher energy sales and lower revenues subject to refund. Revenues
subject to refund were $1.5 million in 2001 compared to $6.9 million in 2000.
See Note 3 to the financial statements under "Retail Revenue Sharing Plan" for
further information.

    "Regulatory cost recovery and other" includes: recovery provisions for fuel
expenses and the energy component of purchased power costs, energy conservation
costs, purchased power capacity costs, and environmental compliance costs.
Annually, the Company seeks recovery of projected costs plus any true-up amount
from prior periods. Approved rates are implemented each January. Therefore, the
recovery provisions generally equal the related expenses and have no material
effect on net income. See Notes 1 and 3 to the financial statements under
"Revenues and Regulatory Cost Recovery Clauses" and "Environmental Cost
Recovery," respectively, for further information.

   Sales for resale were $109.5 million in 2001, a decrease of $24.4 million, or
18.2 percent, from 2000 primarily due to reduced energy sales for resale to
affiliates. Revenues from sales to utilities outside the service area under
long-term contracts consist of capacity and energy components. Capacity revenues
reflect the recovery of fixed costs and a return on investment under the
contracts. Energy is generally sold at variable cost. The capacity and energy
components under these long-term contracts were as follows:

                             2001         2000          1999
                     ----------------------------------------
                                    (in thousands)
Capacity                  $19,472      $20,270       $19,792
Energy                     27,579       21,922        20,251
-------------------------------------------------------------
Total                     $47,051      $42,192       $40,043
=============================================================

   Capacity revenues remained relatively unchanged during 2001 and 2000.

   Sales to affiliated companies vary from year to year depending on demand and
the availability and cost of generating resources at each company. These sales
have little impact on earnings.

   Other operating revenues for 2000 increased due primarily to higher franchise
fees and higher revenues from the transmission of electricity to others.


                                     II-119


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


Energy Sales

Kilowatt-hour sales for 2001 and the percent changes by year were as follows:

                         KWH          Percent Change
                     --------------------------------
                         2001         2001      2000
                     --------------------------------
                       (millions)
Residential                 4,716     (1.5)%     7.1%
Commercial                  3,418      1.2       4.9
Industrial                  2,018      4.8       4.3
Other                          21     10.5       0.0
                     -------------
Total retail               10,173      0.6       5.8
Sales for resale
   Non-affiliates           2,093     22.8       9.2
   Affiliates                 963    (49.8)    (23.7)
                     -------------
Total                      13,229     (3.7)      0.7
=====================================================

   Total retail energy sales increased in both 2001 and 2000 primarily due to an
increase in the total number of customers.

   An increase in energy sales for resale to non-affiliates of 22.8 percent in
2001 when compared to 2000 is primarily related to unit power sales under
long-term contracts to other Florida utilities and bulk power sales under
short-term contracts to other non-affiliated utilities. Energy sales to
affiliated companies vary from year to year depending on demand and availability
and cost of generating resources at each company.

Expenses

Total operating expenses in 2001 increased $13.5 million, or 2.3 percent, over
the amount recorded in 2000 due primarily to higher purchased power expenses and
maintenance expenses. In 2000, total operating expenses increased $39.5 million,
or 7.1 percent, compared to 1999 due primarily to higher fuel and purchased
power expenses.

   Fuel expenses in 2001, when compared to 2000, decreased $15.1 million, or 7.0
percent, due primarily to decreased generation, while average fuel costs
increased as noted below. In 2000, fuel expenses increased $6.7 million, or 3.2
percent, when compared to 1999. The increase in 2000 was a result of an increase
in average fuel costs.

   The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:

                                          2001       2000       1999
                                      -------------------------------
Total generation
   (millions of kilowatt-hours)         11,423     12,866     13,095
Sources of generation
   (percent)
   Coal                                   99.0       98.2       97.4
   Oil and gas                             1.0        1.8        2.6
Average cost of fuel per net
   kilowatt-hour generated
   (cents)--                              1.76       1.68       1.60
---------------------------------------------------------------------

   Purchased power expenses increased in 2001 by $23.8 million, or 28.8 percent,
over 2000 primarily due to an increase in purchased power from affiliate
companies. Purchased power expenses for 2000 increased over 1999 by $25.5
million, or 44.7 percent, due primarily to a higher demand for energy.

   Purchases of energy from affiliates will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These purchases have little impact on earnings.

   Depreciation and amortization expense increased $1.3 million, or 2.0 percent,
in 2001, and $2.3 million, or 3.5 percent, in 2000 due to an increase in
depreciable property and the amortization of a portion of a regulatory asset,
which was allowed in the current retail revenue sharing plan.

   Other income, net increased in 2001 by $6.8 million compared to 2000 due
primarily to higher allowance for equity funds used during construction related
to the Company's new combined cycle unit. In 2000, other income, net decreased
$2.8 million due primarily to expenses related to the discontinuance of the
Company's appliance sales division. See Note 1 to the financial statements under
"Other Income" for further information.

   Interest expense, net decreased $3.1 million, or 10.9 percent, in 2001 due
primarily to higher allowance for debt funds used during construction related to
the Company's new combined cycle unit, as well as lower interest rates on notes
payable and variable rate pollution control bonds. These decreases were
partially offset by the issuance of $60 million of senior notes in August 2001
and $75 million of senior notes in October 2001. In 2000, interest expense, net


                                     II-120


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report

increased $1.2 million, or 4.6 percent, due primarily to the issuance of $50
million of senior notes in August 1999.

Effects of Inflation

The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its cost of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.

Future Earnings Potential

General

The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors. The major factor is the ability to achieve energy sales growth
while containing costs in a more competitive environment.

   In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash income of
approximately $5.9 million in 2001. Future pension income is dependent on
several factors including trust earnings and changes to the plan.

    The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.

   The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
northwest Florida. Prices for electricity provided by the Company to retail
customers are set by the Florida Public Service Commission (FPSC).

   Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included the rate of economic growth in the Company's service area, weather,
competition, changes in contracts with neighboring utilities, the elasticity of
demand, and energy conservation practiced by the Company's customers. The
Company is actively pursuing additional earnings through unregulated new
products and services.

   In early 1999, the FPSC staff and the Company became involved in discussions
primarily related to reducing the Company's authorized rate of return. On
October 1, 1999, the Office of Public Counsel, the Coalition for Equitable
Rates, the Florida Industrial Power Users Group, and the Company jointly filed a
petition to resolve the issues. The stipulation included a reduction to retail
base rates of $10 million annually and provides for revenues to be shared within
set ranges for 1999 through 2002. Customers receive two-thirds of any revenue
within the sharing range and the Company retains one-third. Any revenue above
this range is refunded to the customers. The stipulation also included
authorization for the Company, at its discretion, to accrue up to an additional
$5 million to the property insurance reserve and $1 million to amortize a
regulatory asset related to the corporate office. The Company also filed a
request to prospectively reduce its authorized return on equity (ROE) range from
11 to 13 percent to 10.5 to 12.5 percent in order to help ensure that the FPSC
would approve the stipulation. The FPSC approved both the stipulation and the
ROE request with an effective date of November 4, 1999.

   On September 10, 2001, the Company filed a request with the FPSC for a base
rate increase of approximately $70 million, the majority of which is needed to
recover costs related to the Smith Unit 3 combined cycle facility currently
under construction and scheduled to be placed in service by June 2002. Hearings
are scheduled for February 25 through March 1, 2002 with a decision expected in
early May 2002 and new rates effective June 6, 2002.

   For calendar year 2001, the Company's retail revenue range for sharing was
$358 million to $374 million. Actual retail revenues in 2001 were $360.3 million
and the Company recorded revenues subject to refund of $1.5 million. The
estimated refund with interest was reflected in customer billings in February
2002. For calendar year 2002, there are specified sharing ranges for each month
from the expected in-service date of Smith Unit 3 until the end of the year. The


                                     II-121

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


sharing plan will expire at the earlier of the in-service date of Smith Unit 3
or December 31, 2002.

   Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters." Also, Florida legislation adopted in 1993 that provides
for recovery of prudent environmental compliance costs is discussed in Note 3 to
the financial statements under "Environmental Cost Recovery."

Industry Restructuring

The electric utility industry in the United States is continuing to evolve as
a result of regulatory and competitive factors. Among the primary agents of
change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act
allows independent power producers (IPPs) to access a utility's transmission
network in order to sell electricity to other utilities. This enhances the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.

   Although the Energy Act does not permit retail customer access, it has been a
major catalyst for recent restructuring and consolidations taking place within
the utility industry. Numerous federal and state initiatives are in varying
stages to promote wholesale and retail competition. Among other things, these
initiatives allow customers to choose their electricity provider. Some states
have approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While various restructuring and
competition initiatives have been discussed in Florida, none have been enacted.
Enactment would require numerous issues to be resolved, including significant
ones relating to recovery of any stranded investments, full cost recovery of
energy produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation.

   In 2000, Florida's Governor appointed a 17 member study commission to look at
the state's electric industry, studying issues ranging from current and future
reliability of electric and natural gas supply, electric industry retail and
wholesale competition, environmental impacts of energy supply, conservation, and
tax issues. A deadline of December 1, 2001 was set for the commission's final
report and recommendations to the Governor and the Legislature. During the
course of the study, the Stranded Investment Task Force Subcommittee recommended
a discretionary transfer approach regarding the transfer or sale of generation
assets by an investor owned utility (IOU). This would allow all new generation
to be competitively bid while allowing IOU's to transfer generation units to an
affiliate or sell generation units and share proceeds with both shareholders and
consumers. Merchants would also be allowed to compete in this restructured
wholesale market. This recommendation was approved during the final meeting of
the study commission on November 15, 2001 and has been incorporated into the
final report. The final report, entitled "Florida...Energy Wise" was presented
on December 11, 2001 to the Governor and the Legislature. Any recommendations
from the commission will have to be drafted and voted into law by the
Legislature. This is unlikely to occur in the upcoming 2002 legislative session.
The effects of any proposed changes cannot presently be determined, but could
have a material effect on the Company's financial condition and results of
operations.

    Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the Company does not remain a low-cost producer and provide
quality service, then energy sales growth could be limited, and this could
significantly erode earnings.

    In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
Southern Company explained that it is developing a for profit RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public


                                     II-122


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the SeTrans RTO. Southern Company continues to work with the
other sponsors to develop the SeTrans RTO. The creation of SeTrans is not
expected to have a material impact on the Company's financial statements. The
outcome of this matter cannot now be determined.

Accounting Policies

Critical Policy

Gulf Power Company's significant accounting policies are described in Note 1 to
the financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operations is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.

New Accounting Standards

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. The
impact on net income in 2001 was not material. (See Note 1 to the financial
statements under "Financial Instruments" for additional information). An
additional interpretation of Statement No. 133 will result in a change --
effective April 1, 2002 -- in accounting for certain contracts related to fuel
supplies that contain quantity options. These contracts will be accounted for as
derivatives and marked to market. However, due to the existence of specific
cost-based fuel recovery clauses for the Company, this change is not expected to
have a material impact on net income.

   In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No. 142 in January 2002 with no material
impact on the financial statements.

   Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.

FINANCIAL CONDITION

Overview

During 2001, gross property additions were $274.7 million. Funds for the
Company's property additions were provided by operating activities and
additional financings, which were utilized to finance the construction of the
Company's new combined cycle unit. See the Statements of Cash Flows for further
details.

Credit Rating Risk

The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.

                                     II-123



<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


Exposure to Market Risks

Due to cost-based rate regulations, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market and, to a lesser extent,
similar contracts for gas purchases. Realized gains and losses are recognized in
the income statement as incurred. At December 31, 2001, exposure from these
activities was not material. Fair value of changes in energy trading contracts
and year-end valuations are as follows:

                                         Changes During the Year
----------------------------------------------------------------
                                                    Fair Value
----------------------------------------------------------------
                                                 (in thousands)
Contracts beginning of year                          $110
Contracts realized or settled                        (100)
New contracts at inception                              -
Changes in valuation techniques                         -
Current period changes                               (120)
----------------------------------------------------------------
Contracts end of year                               $(110)
================================================================

                        Source of Year-End Valuation Prices
----------------------------------------------------------------
                                            Maturity
                            Total          ---------
                          Fair Value      Year 1     1-3 Years
----------------------------------------------------------------
                                     (in thousands)
Actively quoted           $(110)       $(102)          $(8)
External sources              -            -             -
Models and other
   methods                    -            -             -
----------------------------------------------------------------
Contracts end of year     $(110)       $(102)          $(8)
================================================================

   If the Company sustained a 100 basis point change in interest rates for all
variable rate long-term debt, the change would affect annualized interest
expense by approximately $0.61 million at December 31, 2001.

Financing Activities

In 2001, the Company sold $135 million of senior notes and $30 million of trust
preferred securities and used the proceeds to retire $30 million of first
mortgage bonds and to pay for construction of the Company's new combined cycle
unit. In 2000, there were no issuances or retirements of long-term debt. See the
Statements of Cash Flows for further details.

   Composite financing rates for the years 1999 through 2001 as of year end were
as follows:

                                       2001      2000      1999
                                    -----------------------------
Composite interest rate on
   long-term debt                       5.6%      6.2%      6.0%
Composite rate on
   trust preferred securities           7.2%       7.3%     7.3%
Composite preferred stock
   dividend rate                        5.1%      5.1%      5.1%
-----------------------------------------------------------------

   The composite interest rate on long-term debt decreased in 2001 due to lower
interest rates on variable rate pollution control bonds and lower rates on new
senior notes.

Capital Requirements for Construction

The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $282 million for the three years
beginning in 2002 ($103 million in 2002, $72 million in 2003, and $107 million
in 2004). These amounts include $24.3 million in 2002 for the remaining cost of
a 574 megawatt combined cycle gas generating unit and related interconnections
to be located in the eastern portion of the Company's service area. The unit is
expected to have an in-service date of June 2002. The remaining property
additions budget is primarily for maintaining and upgrading transmission and
distribution facilities and generating plants. Actual construction costs may
vary from this estimate because of changes in such factors as the following:
business conditions; environmental regulations; load projections; the cost and
efficiency of construction labor, equipment, and materials; and the cost of
capital. In addition, there can be no assurance that costs related to capital
expenditures will be fully recovered.

Other Capital Requirements

The Company will continue to retire higher-cost debt and preferred securities
and replace these securities with lower-cost capital as market conditions and
terms of the instruments permit.


                                     II-124
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


   Future note maturities, operating lease obligations, and purchase
commitments - discussed in notes 4 and 8 to the financial statements --
are as follows:

                                    2002      2003      2004
--------------------------------------------------------------
                                          (in millions)
Bonds -
   First mortgage                   $  -  $      -      $   -
   Pollution control                   -         -          -
Notes                                  -        61         51
Leases -
   Capital                             -         -          -
   Operating                           2         2          2
--------------------------------------------------------------
Purchase commitments
   Fuel                              140       109        112
   Purchased power                     2         1          1
--------------------------------------------------------------

   At the beginning of 2002, the Company had not used any of its available
credit arrangements. Credit arrangements are as follows:

                                             Expires
                                 -----------------------------
   Total         Unused           2002        2003 & beyond
--------------------------------------------------------------
                           (in millions)
    $103           $103           $103                $   -
--------------------------------------------------------------

Environmental Matters

In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) was
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected the Company. Specific reductions
in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating
plants were required in two phases. Phase I compliance began in 1995. Southern
Company achieved Phase I compliance at the affected plants by primarily
switching to low-sulfur coal and with some equipment upgrades. Construction
expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance
totaled approximately $42 million for the Company. Phase II sulfur dioxide
compliance was required in 2000. Southern Company used emission allowances and
fuel switching to comply with Phase II requirements. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits and ozone non-attainment requirements for
metropolitan Atlanta through 2000. Phase II compliance did not have a material
impact on the Company.

   A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.

   In 1993, the Florida Legislature adopted legislation that allows a utility to
petition the FPSC for recovery of prudent environmental compliance costs that
are not being recovered through base rates or any other recovery mechanism. The
legislation is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery." Substantially all of the costs for the Clean Air
Act and other new environmental legislation discussed below are expected to be
recovered through the Environmental Cost Recovery Clause.

   In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
made the standards significantly more stringent. In the subsequent litigation of
these standards, the U.S. Supreme Court found the EPA's implementation program
for the new ozone standard unlawful and remanded it to the EPA. In addition, the
Federal District of Columbia Circuit Court of Appeals is considering other legal
challenges to these standards. If the standards are eventually upheld,
implementation could be required by 2007 to 2010.

   In September 1998, the EPA issued regional nitrogen oxide reduction rule to
the states for implementation. Compliance is required by May 31, 2004 for most
states, but for Georgia, further ratemaking is required and compliance may be
delayed until May 2005. The final rule affects 21 states, including Georgia, but
not Florida. See Note 5 to the financial statements under "Joint Ownership
Agreements" related to the Company's ownership interest in Georgia Power's Plant
Scherer Unit No. 3. The EPA is presently evaluating whether to bring an
additional 15 states, not including Florida, under this regional nitrogen oxide
rule.

   In December 2000, the EPA completed its utility study for mercury and other
hazardous air pollutants (HAPS) and issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is to be developed over the next four years under the Maximum Achievable Control
Technology provisions of the Clean Air Act, and the regulations are scheduled to
be finalized by the end of 2004 with implementation to take place around 2007.
In January 2001, the EPA proposed guidance for the determination of Best

                                     II-125


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


Available Retrofit Technology (BART) emission controls under the Regional Haze
Regulations. Installation of BART controls is expected to take place around
2010. Litigation of the Regional Haze Regulations, including the BART
provisions, is ongoing in the Federal District of Columbia Circuit Court of
Appeals. A court decision is expected in mid-2002.

   Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.

   In October 1997, EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by EPA in March 2001 in response to a
court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.

   The EPA and state environmental regulatory agencies are also reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.

   On November 3, 1999, the EPA brought a civil action in the U.S. District
Court against Alabama Power, Georgia Power, and the system service company. The
complaint alleges violations of the prevention of significant deterioration and
new source review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. For additional
information, see Note 5 to the financial statements under "Joint Ownership
Agreements" related to the Company's ownership interest in Georgia Power's Plant
Scherer Unit No. 3. In early 2000, the EPA filed a motion to amend its complaint
to add the violations alleged in its notice of violation, and to add the
Company, Mississippi Power, and Savannah Electric as defendants. The complaint
and notice of violation are similar to those brought against and issued to
several other electric utilities. These complaints and notices of violation
allege that the utilities had failed to secure necessary permits or install
additional pollution control equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. The U.S. District Court granted Alabama Power's motion to dismiss for lack
of jurisdiction in Georgia and granted the system service company's motion to
dismiss on the grounds that it neither owned nor operated the generating units
involved in the proceedings. The court directed the EPA to re-file its amended
complaint limiting claims to those brought against Georgia Power and Savannah
Electric. The EPA re-filed those claims as directed by the court. Also, the EPA
re-filed its claims against Alabama Power in U.S. District Court in Alabama. It
has not re-filed against the Company, Mississippi Power, or the system service
company. The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.

   The Company believes that it has complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit. Prior to January 30, 1997, the penalty was
$25,000 per day. An adverse outcome of this matter could require substantial


                                     II-126


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows, and possibly financial condition if such costs are not
recovered through regulated rates.

   The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup
costs and has recognized in the financial statements costs to clean up known
sites. For additional information, see Note 3 to the financial statements under
"Environmental Cost Recovery."

   Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.

    Compliance with possible additional legislation related to global climate
change, electric and magnetic fields, and other environmental health concerns
could significantly affect the Company. The impact of new legislation -- if any
-- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electric and magnetic fields.

Sources of Capital

At December 31, 2001, the Company had approximately $2.2 million of cash and
cash equivalents and $2.6 million of unused commercial paper backed by lines of
credit with banks to meet its short-term cash needs. See the Statements of Cash
Flows for details related to the Company's financing activities. See Note 8 to
the financial statements under "Bank Credit Arrangements" for additional
information.

   The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $37.4 million of commercial
paper.

   The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control bonds issued for its benefit
by public authorities, to meet its long-term external financing requirements.
Recently, the Company's financings have consisted of unsecured debt and trust
preferred securities. The Company has no restrictions on the amounts of
unsecured indebtedness it may incur. However, in order to issue first mortgage
bonds or preferred stock, the Company is required to meet certain coverage
requirements specified in its mortgage indenture and corporate charter. The
Company's ability to satisfy all coverage requirements is such that it could
issue new first mortgage bonds and preferred stock to provide sufficient funds
for all anticipated requirements.

Cautionary Statement Regarding Forward-Looking Information

The Company's 2001 Annual Report contains forward looking and historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "could," "should," "expects," "plans,"
"anticipates," "believes," "estimates," "projects," "predicts," "potential" or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action; the effects, extent, and timing of the entry of additional competition
in the markets of the Company; the impact of fluctuations in commodity prices,
interest rates and customer demand; state and federal rate regulations;
political, legal, and economic conditions and developments in the United States;
the performance of projects undertaken by the non-traditional business and the
success of efforts to invest in and develop new opportunities; internal


                                     II-127
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS  (continued)
Gulf Power Company 2001 Annual Report


restructuring or other restructuring options that may be pursued; potential
business strategies, including acquisitions or dispositions of assets or
businesses, which cannot be assured to be completed or beneficial to the Company
the effects of, and changes in, economic conditions in the Company's service
territory; the direct or indirect effects on the Company's business resulting
from the terrorist incident on September 11, 2001, or any similar such incidents
or responses to such incidents; the timing and acceptance of the Company's new
product and services offerings; financial market conditions and the results of
financing efforts; weather and other natural phenomena; the ability of the
Company to obtain additional generating capacity at competitive prices; and
other factors discussed elsewhere herein and in other reports (including Form
10-K) filed from time to time by the Company with the Securities and Exchange
Commission.


                                     II-128
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Gulf Power Company 2001 Annual Report

------------------------------------------------------------------------------------------------------------------
                                                                    2001                 2000                1999
------------------------------------------------------------------------------------------------------------------
                                                                              (in thousands)
Operating Revenues:
<S>                                                             <C>                  <C>                 <C>
Retail sales                                                    $584,591             $548,640            $516,949
Sales for resale --
  Non-affiliates                                                  82,252               66,890              62,354
  Affiliates                                                      27,256               66,995              66,110
Other revenues                                                    31,104               31,794              28,686
------------------------------------------------------------------------------------------------------------------
Total operating revenues                                         725,203              714,319             674,099
------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                           200,633              215,744             209,031
  Purchased power --
    Non-affiliates                                                65,585               73,846              46,332
    Affiliates                                                    40,660                8,644              10,703
Other                                                            117,394              117,146             114,670
Maintenance                                                       60,193               56,281              57,830
Depreciation and amortization                                     68,218               66,873              64,589
Taxes other than income taxes                                     55,261               55,904              51,782
------------------------------------------------------------------------------------------------------------------
Total operating expenses                                         607,944              594,438             554,937
------------------------------------------------------------------------------------------------------------------
Operating Income                                                 117,259              119,881             119,162
Other Income (Expense):
Interest income                                                    1,258                1,137               1,771
Other, net                                                         2,710               (4,126)             (1,357)
------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                        121,227              116,892             119,576
------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net                                             25,034               28,085              26,861
Distributions on preferred securities of subsidiary                6,477                6,200               6,200
------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                             31,511               34,285              33,061
------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                      89,716               82,607              86,515
Income taxes (Note 7)                                             31,260               30,530              32,631
------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of                              58,456               52,077              53,884
   Accounting Change
Cumulative effect of accounting change--
  less income taxes of $42 thousand                                   68                    -                   -
------------------------------------------------------------------------------------------------------------------
Net Income                                                        58,524               52,077              53,884
Dividends on Preferred Stock                                         217                  234                 217
------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock                   $ 58,307             $ 51,843            $ 53,667
==================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>


                                                              II-129
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Gulf Power Company 2001 Annual Report

------------------------------------------------------------------------------------------------------------------------
                                                                          2001                 2000                1999
------------------------------------------------------------------------------------------------------------------------
                                                                                    (in thousands)
Operating Activities:
<S>                                                                  <C>                  <C>                 <C>
Net income                                                           $  58,524            $  52,077           $  53,884
Adjustments to reconcile net income
 to net cash provided from operating activities --
      Depreciation and amortization                                     72,320               69,915              68,721
      Deferred income taxes, net                                         3,394              (12,516)             (6,609)
      Other, net                                                        (1,804)              10,686               3,735
      Changes in certain current assets and liabilities --
        Receivables, net                                                15,991              (20,212)            (10,484)
        Fossil fuel stock                                              (30,887)              13,101              (5,656)
        Materials and supplies                                             176                1,055              (2,063)
        Accounts payable                                               (14,492)              15,924              (2,023)
        Provision for rate refund                                        1,530                7,203                   -
        Other                                                          (31,249)              12,521               7,030
------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                             73,503              149,754             106,535
------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                              (274,668)             (95,807)            (69,798)
Other                                                                    5,290               (4,432)             (8,856)
------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                (269,378)            (100,239)            (78,654)
------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                               44,311              (12,000)             23,500
Proceeds --
    Other long-term debt                                               135,000                    -              50,000
    Preferred securities                                                30,000                    -                   -
    Capital contributions from parent company                           72,484               12,222               2,294
Retirements --
    First mortgage bonds                                               (30,000)                   -                   -
    Other long-term debt                                                  (862)              (1,853)            (27,074)
    Preferred stock                                                          -                    -                   -
Payment of preferred stock dividends                                      (217)                (234)               (271)
Payment of common stock dividends                                      (53,275)             (59,000)            (61,300)
Other                                                                   (3,703)                 (22)               (246)
------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities                 193,738              (60,887)            (13,097)
------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                 (2,137)             (11,372)             14,784
Cash and Cash Equivalents at Beginning of Period                         4,381               15,753                 969
------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                            $  2,244            $   4,381           $  15,753
========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
    Interest (net of amount capitalized)                               $30,813              $32,277             $27,670
    Income taxes (net of refunds)                                       33,349               42,252              29,462
------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.

</TABLE>






                                                              II-130

<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Gulf Power Company 2001 Annual Report

-------------------------------------------------------------------------------------------------------------
Assets                                                                         2001                     2000
-------------------------------------------------------------------------------------------------------------
                                                                                      (in thousands)
Current Assets:
<S>                                                                         <C>                      <C>
Cash and cash equivalents                                                   $ 2,244                  $ 4,381
Receivables --
  Customer accounts receivable                                               64,113                   69,820
  Other accounts and notes receivable                                         4,316                    2,179
  Affiliated companies                                                        2,689                   15,026
  Accumulated provision for uncollectible accounts                           (1,342)                  (1,302)
Fossil fuel stock, at average cost                                           47,655                   16,768
Materials and supplies, at average cost                                      28,857                   29,033
Regulatory clauses under recovery                                            24,912                    2,112
Other                                                                        12,662                    6,543
-------------------------------------------------------------------------------------------------------------
Total current assets                                                        186,106                  144,560
-------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service                                                                1,951,512                1,892,023
Less accumulated provision for depreciation                                 912,581                  867,260
-------------------------------------------------------------------------------------------------------------
                                                                          1,038,931                1,024,763
Construction work in progress                                               264,525                   71,008
-------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                      1,303,456                1,095,771
-------------------------------------------------------------------------------------------------------------
Other Property and Investments                                                7,049                    4,510
-------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 7)                            16,766                   15,963
Prepaid pension costs (Note 2)                                               26,364                   20,058
Debt expense, being amortized                                                 3,036                    2,392
Premium on reacquired debt, being amortized                                  14,518                   15,866
Other                                                                        12,222                   12,944
-------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                      72,906                   67,223
-------------------------------------------------------------------------------------------------------------
Total Assets                                                             $1,569,517               $1,312,064
=============================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>



                                                              II-131


<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Gulf Power Company 2001 Annual Report

--------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                            2001                     2000
--------------------------------------------------------------------------------------------------------------
                                                                                       (in thousands)
Current Liabilities:
<S>                                                                         <C>                      <C>
Notes payable                                                               $ 87,311                 $ 43,000
Accounts payable --
  Affiliated                                                                  18,202                   17,558
  Other                                                                       38,308                   38,153
Customer deposits                                                             14,506                   13,474
Taxes accrued --
  Income taxes                                                                 8,162                    3,864
  Other                                                                        8,053                    8,749
Interest accrued                                                               8,305                    8,324
Provision for rate refund                                                      1,530                    7,203
Vacation pay accrued                                                           4,725                    4,512
Regulatory clauses over recovery                                               3,719                    6,848
Other                                                                          6,528                    1,584
--------------------------------------------------------------------------------------------------------------
Total current liabilities                                                    199,349                  153,269
--------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                 467,784                  365,993
--------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7)                                   161,968                  155,074
Deferred credits related to income taxes (Note 7)                             28,293                   38,255
Accumulated deferred investment tax credits                                   24,056                   25,792
Employee benefits provisions                                                  37,892                   31,075
Other                                                                         26,045                   25,992
--------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                 278,254                  276,188
--------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
  securities of subsidiary trusts holding company junior
  subordinated notes (See accompanying statements)                           115,000                   85,000
--------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements)                                  4,236                    4,236
--------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                    504,894                  427,378
--------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                $1,569,517               $1,312,064
==============================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>

                                                              II-132


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Gulf Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                                    2001             2000              2001           2000
-----------------------------------------------------------------------------------------------------------------------------
                                                                         (in thousands)               (percent of total)
Long Term Debt:
First mortgage bonds --
       Maturity                           Interest Rates
       ---------                          --------------
       <S>                               <C>                        <C>         <C>                  <C>              <C>
       July 1, 2003                       6.125%                 $     -         $ 30,000
       November 1, 2006                   6.50%                   25,000           25,000
       January 1, 2026                    6.875%                  30,000           30,000
-----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                        55,000           85,000
-----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
  4.69% due August 1, 2003                                        60,000                -
  7.05% due August 15, 2004                                       50,000           50,000
  6.10% due September 30, 2016                                    75,000                -
  7.50% due June 30, 2037                                         20,000           20,000
  6.70% due June 30, 2038                                         47,211           48,073
-----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable                                    252,211          118,073
-----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
      Pollution control revenue bonds --
        Collateralized:
         5.25% to 6.30% due 2006-2026                            108,700          108,700
        Non-collateralized:
         Variable rates (1.75% to 1.95% at 1/1/02)
          due 2022-2024                                           60,930           60,930
-----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                       169,630          169,630
-----------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net                          (9,057)          (6,710)
-----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
  requirement -- $29.2 million)                                  467,784          365,993             42.9%            41.5%
-----------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value, 4.64% to 5.44%                                     4,236            4,236
-----------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $0.2 million)                4,236            4,236              0.4%             0.5%
-----------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
  Redeemable Preferred Securities:
$25 liquidation value --
  7.00%                                                           45,000           45,000
  7.38%                                                           30,000                -
  7.63%                                                           40,000           40,000
-----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $8.4 million)          115,000           85,000             10.5%             9.6%
-----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
  Authorized and outstanding -
   992,717 shares in 2001 and 2000                                38,060           38,060
  Paid-in capital                                                305,960          233,476
  Premium on preferred stock                                          12               12
Retained earnings                                                160,862          155,830
-----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                                504,894          427,378             46.2%            48.4%
-----------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                          $1,091,914         $882,607            100.0%           100.0%
=============================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>


                                                              II-133


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Gulf Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------------

                                                                                 Premium on
                                                     Common         Paid-In       Preferred        Retained
                                                      Stock         Capital         Stock          Earnings           Total
-----------------------------------------------------------------------------------------------------------------------------
                                                                               (in thousands)

<S>                                                  <C>            <C>                <C>        <C>              <C>
Balance at January 1, 1999                            $38,060        $218,960           $12        $170,620         $427,652
Net income after dividends on preferred stock               -               -             -          53,667           53,667
Capital contributions from parent company                   -           2,294             -               -            2,294
Cash dividends on common stock                              -               -             -         (51,300)         (51,300)
Other                                                       -               -             -         (10,000)         (10,000)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                           38,060         221,254            12         162,987          422,313
Net income after dividends on preferred stock               -               -             -          51,843           51,843
Capital contributions from parent company                   -          12,222             -               -           12,222
Cash dividends on common stock                              -               -             -         (59,000)         (59,000)
Balance at December 31, 2000                           38,060         233,476            12         155,830          427,378
-----------------------------------------------------------------------------------------------------------------------------
Net income after dividends on preferred stock               -               -             -          58,307           58,307
Capital contributions from parent company                   -          72,484             -               -           72,484
Cash dividends on common stock                              -               -             -         (53,275)         (53,275)
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001                          $38,060        $305,960           $12        $160,862         $504,894
=============================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>




                                                              II-134


<PAGE>
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2001 Annual Report

1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

Gulf Power Company (Company) is a wholly owned subsidiary of Southern Company,
which is the parent company of five operating companies, a system service
company (SCS), Southern Communications Services (Southern LINC), Southern
Nuclear Operating Company (Southern Nuclear), Southern Power Company (Southern
Power), and other direct and indirect subsidiaries. The operating companies --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- provide electric service in four southeastern states. Contracts
among the operating companies -- related to jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. SCS provides, at cost, specialized services
to Southern Company and subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Power was
established in 2001 to construct, own, and manage Southern Company's competitive
generation assets and sell electricity at market-based rates in the wholesale
market.

   Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Florida Public Service Commission
(FPSC). The Company follows accounting principles generally accepted in the
United States and complies with the accounting policies and practices prescribed
by the FPSC and the FERC. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the
use of estimates, and the actual results may differ from those estimates.

   Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension administration, human resources,
systems and procedures, and other services with respect to business and
operations and power pool operations. Costs for these services amounted to $45
million, $44 million, and $43 million during 2001, 2000, and 1999, respectively.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:

                                              2001          2000
                                        --------------------------
                                             (in thousands)
Deferred income tax charges               $ 16,766      $ 15,963
Deferred loss on reacquired
 debt                                       14,518        15,866
Environmental remediation                    7,163         7,638
Vacation pay                                 4,725         4,512
Accumulated provision for
   rate refunds                             (1,530)      (7,203)
Accumulated provision for
   property damage                         (13,565)       (8,731)
Deferred income tax credits                (28,293)      (38,255)
Other, net                                  (1,443)       (1,074)
------------------------------------------------------------------
Total                                     $ (1,659)     $(11,284)
==================================================================

   In the event that a portion of the Company's operations is no longer subject
to the provisions of FASB Statement No. 71, the Company would be required to
write off related regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine any impairment to other assets, including plant, and write down the
assets, if impaired, to their fair value.


                                     II-135


<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


Revenues and Regulatory Cost Recovery Clauses

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its service area located in northwest
Florida and to wholesale customers in the Southeast.

   Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period.

   Fuel costs are expensed as the fuel is used. The Company's retail electric
rates include provisions to annually adjust billings for fluctuations in fuel
costs, the energy component of purchased power costs, and certain other costs.
The Company also has similar retail cost recovery clauses for energy
conservation costs, purchased power capacity costs, and environmental compliance
costs. Revenues are adjusted monthly for differences between recoverable costs
and amounts actually reflected in current rates.

   The Company has a diversified base of customers and no single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts averaged significantly less than 1 percent of revenues.

Depreciation and Amortization

Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.7 percent in 2001 and
3.8 percent in both 2000, and 1999. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to the accumulated
provision for depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired. Also,
the provision for depreciation expense includes an amount for the expected cost
of removal of facilities.

Other Income

Other income consists principally of interest and dividend income, Allowance for
Funds Used During Construction (AFUDC)-equity, and income or expenses on other
non-regulated activities. In 2000 and 1999, the non-regulated activities
included the results of the Company's merchandising operations, which were
discontinued in the latter part of 2000.

Income Taxes

The Company uses the liability method of accounting for income taxes and
provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction. The cost of
maintenance, repairs, and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property (exclusive of minor
items of property) is charged to utility plant.

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in
circumstances indicate that the carrying value of such assets may not be
recoverable. The determination of whether an impairment has occurred is based on
an estimate of undiscounted future cash flows attributable to the assets, as
compared to the carrying value of the assets. If an impairment has occurred, the
amount of the impairment recognized is determined by estimating the fair value
of the assets and recording a provision for loss if the carrying value is
greater than the fair value. For assets identified as held for sale, the
carrying value is compared to the estimated fair value less the cost to sell in
order to determine if an impairment provision is required. Until the assets are
disposed of, their estimated fair value is re-evaluated when circumstances or
events change.

Cash and Cash Equivalents

Temporary cash investments are considered cash equivalents. Temporary cash
investments are securities with original maturities of 90 days or less.

Financial Instruments

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended.  The impact on
net income was immaterial.

                                     II-136



<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


   The Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, and certain commodity prices. Gains and losses
on qualifying hedges are deferred and recognized either in income or as an
adjustment to the carrying amount of the hedged item when the transaction
occurs.

   The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.

   The Company and its affiliates, through SCS acting as their agent, enters
into commodity related forward and option contracts to limit exposure to
changing prices on certain fuel purchases and electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales contracts
meet the definition of a derivative under FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities. In many cases, these fuel and
electricity contracts qualify for normal purchase and sale exceptions under
Statement No. 133 and are accounted for under the accrual method. Other
contracts qualify as cash flow hedges of anticipated transactions, resulting in
the deferral of related gains and losses, and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.

   Other financial instruments for which the carrying amount did not equal fair
value at December 31 were as follows:

                                       Carrying          Fair
                                         Amount         Value
                                   ---------------------------
                                          (in thousands)
Long-term debt:
   At December 31, 2001                $467,784      $474,911
   At December 31, 2000                $365,993      $364,697
Capital trust preferred
securities:
   At December 31, 2001                $115,000      $114,898
   At December 31, 2000                 $85,000       $80,988
--------------------------------------------------------------

   The fair values for long-term debt and preferred securities were based on
either closing market prices or closing prices of comparable instruments.

Materials and Supplies

Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.

Provision for Injuries and Damages

The Company is subject to claims and suits arising in the ordinary course of
business. As permitted by regulatory authorities, the Company provides for the
uninsured costs of injuries and damages by charges to income amounting to $1.2
million annually. The expense of settling claims is charged to the provision to
the extent available. The accumulated provision of $1.3 million and $1.2 million
at December 31, 2001 and 2000, respectively, is included in other current
liabilities in the accompanying Balance Sheets.

Provision for Property Damage

The Company provides for the cost of repairing damages from major storms and
other uninsured property damages. This includes the full cost of major storms
and other damages to its transmission and distribution lines and the cost of
uninsured damages to its generation and other property. The expense of such
damages is charged to the provision account. At December 31, 2001 and 2000, the
accumulated provision for property damage was $13.6 million and $8.7 million,
respectively. The FPSC approved annual accrual to the accumulated provision for
property damage is $3.5 million, with a target level for the accumulated
provision account between $25.1 and $36.0 million. The FPSC has also given the
Company the flexibility to increase its annual accrual amount above $3.5 million
at the Company's discretion. The Company accrued $4.5 million in 2001, $3.5
million in 2000, and $5.5 million in 1999 to the accumulated provision for
property damage. The Company had a net credit of $(0.3) million to the provision
account in 2001 related to insurance proceeds that exceeded actual claims. In
2000 and 1999, the Company charged $0.3 million and $1.6 million, respectively,
to the provision account.

2.  RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. The Company provides certain medical
care and life insurance benefits for retired employees. Substantially all
employees may become eligible for these benefits when they retire. Trusts are


                                     II-137


<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


funded to the extent required by the Company's regulatory commissions. In late
2000, the Company adopted several pension and postretirement benefit plan
changes that had the effect of increasing benefits to both current and future
retirees. The measurement date for plan assets and obligations is September 30
for each year.

Pension Plan

Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
                                            Projected
                                       Benefit Obligations
                                    ---------------------------
                                          2001          2000
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $153,214      $146,106
Service cost                              4,703         4,367
Interest cost                            11,644        10,695
Benefits paid                            (8,105)       (7,169)
Actuarial gain and
      employee transfers, net              (195)         (785)
Amendments                                7,997             -
Other                                        (7)            -
---------------------------------------------------------------
Balance at end of year                 $169,251      $153,214
===============================================================

                                           Plan Assets
                                     --------------------------
                                           2001          2000
---------------------------------------------------------------
                                            (in thousands)
Balance at beginning of year           $283,266       $241,485
Actual return on plan assets            (40,841)        43,833
Benefits paid                            (7,758)        (6,973)
Employee transfers                         (961)         4,921
---------------------------------------------------------------
Balance at end of year                 $233,706        $283,266
===============================================================

   The accrued pension costs recognized in the Balance Sheets
were as follows:

                                           2001       2000
---------------------------------------------------------------
                                          (in thousands)
Funded status                          $ 64,455    $ 130,052
Unrecognized transition
    obligation                           (2,832)      (3,503)
Unrecognized prior
    service cost                         11,689        4,529
Unrecognized net gain                   (47,038)    (111,092)
4th quarter cash flow
    adjustment                               90           72
 ---------------------------------------------------------------
Prepaid asset recognized
      in the Balance Sheets            $ 26,364      $20,058
===============================================================

    Components of the pension plan's net periodic cost
were as follows:

                                2001          2000           1999
-------------------------------------------------------------------
Service cost                $  4,703      $  4,367       $  4,556
Interest cost                 11,644        10,695          9,729
Expected return on
  plan assets                (19,312)      (17,504)       (15,968)
Recognized net gain           (3,072)       (2,582)          (234)
Net amortization                 165          (235)        (1,549)
-------------------------------------------------------------------
Net pension income          $ (5,872)     $ (5,259)      $ (3,466)
===================================================================

Postretirement Benefits

Changes during the year in the accumulated benefit obligations
and in the fair value of plan assets were as follows:

                                           Accumulated
                                        Benefit Obligations
                                    ---------------------------
                                          2001           2000
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year            $50,025       $48,010
Service cost                                983           896
Interest cost                             3,886         3,515
Benefits paid                            (1,823)       (1,462)
Amendments                                3,412             -
---------------------------------------------------------------
Actuarial gain                           (2,146)         (934)
---------------------------------------------------------------
Balance at end of year                  $54,337       $50,025
===============================================================

                                           Plan Assets
                                    ---------------------------
                                        2001          2000
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year          $13,388       $11,196
Actual return on plan assets           (1,830)        2,079
Employer contributions                  1,897         1,575
Benefits paid                          (1,823)       (1,462)
---------------------------------------------------------------
Balance at end of year                $11,632       $13,388
===============================================================

    The accrued postretirement costs recognized in the Balance
Sheets were as follows:

                                       2001           2000
----------------------------------------------------------------
                                          (in thousands)
Funded status                         $(42,705)      $(36,638)
Unrecognized transition
      obligation                         4,012          4,368
Unrecognized prior
      service cost                       5,695          2,582
Unrecognized net loss                    1,235            496
Fourth quarter contributions               386            316
----------------------------------------------------------------
Accrued liability recognized
      in the Balance Sheets           $(31,377)      $(28,876)
================================================================

                                     II-138


<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


    Components of the postretirement plan's net periodic cost were as follows:

                                    2001       2000      1999
-----------------------------------------------------------------
Service cost                     $    983    $    896   $  1,087
Interest cost                       3,886       3,515      3,261
Expected return on
      plan assets                  (1,037)       (901)      (794)
Transition obligation                 356         355        356
Prior service cost                    299         159        159
Recognized net
 (gain)/loss                          (18)         13        264
-----------------------------------------------------------------
Net post-retirement cost         $  4,469    $  4,037   $  4,333
=================================================================

   The weighted average rates assumed in the actuarial calculations for both the
pension plan and postretirement benefits plan were:

                                       2001       2000
----------------------------------------------------------
Discount                               7.50%      7.50%
Annual salary increase                 5.00%      5.00%
Long-term return on plan
assets                                 8.50%      8.50%
----------------------------------------------------------

    An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter.

    An annual increase or decrease in the assumed medical care cost trend rate
of 1 percent would affect the accumulated benefit obligation and the service and
interest cost components at December 31, 2001 as follows (in thousands):

                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
Benefit obligation                    $4,575           $3,985
Service and interest costs              $410             $351
===============================================================

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $2.3
million, $2.2 million, and $2.0 million, respectively.

3.   CONTINGENCIES AND REGULATORY
     MATTERS

General

The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.

Environmental Cost Recovery

In 1993, the Florida Legislature adopted legislation for an Environmental Cost
Recovery Clause (ECRC), which allows a utility to petition the FPSC for recovery
of prudent environmental compliance costs that are not being recovered through
base rates or any other recovery mechanism. Such environmental costs include
operation and maintenance expense, emission allowance expense, depreciation, and
a return on invested capital.

   In 1994, the FPSC approved the Company's initial petition under the ECRC for
recovery of environmental costs. During 2001, 2000, and 1999, the Company
recorded ECRC revenues of $10.0 million, $9.9 million, and $11.5 million,
respectively.

   At December 31, 2001, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $7.2 million. These
estimated costs are expected to be expended from 2002 through 2008. These
projects have been approved by the FPSC for recovery through the ECRC discussed
above. Therefore, the Company recorded $1.2 million in current assets and
current liabilities and $6.0 million in deferred assets and deferred liabilities
representing the future recoverability of these costs.

Environmental Litigation

On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and SCS.
The complaint alleges violations of the prevention of significant deterioration
and new source review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action


                                     II-139


<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation
at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day.

   The EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. See Note 5
under "Joint Ownership Agreements" related to the Company's ownership interest
in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a
motion to amend its complaint to add the violations alleged in its notice of
violation, and to add the Company, Mississippi Power, and Savannah Electric as
defendants. The complaint and notice of violation are similar to those brought
against and issued to several other electric utilities. These complaints and
notices of violation allege that the utilities had failed to secure necessary
permits or install additional pollution control equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. On August 1, 2000, the U.S. District Court granted
Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and
granted SCS's motion to dismiss on the grounds that it neither owned nor
operated the generating units involved in the proceedings. The court directed
the EPA to re-file its amended complaint limiting claims to those brought
against Georgia Power and Savannah Electric. The EPA re-filed those claims as
directed by the court. Also, the EPA re-filed its claims against Alabama Power
in U.S. District Court in Alabama. It has not re-filed against the Company,
Mississippi Power, or the system service company. The Alabama Power, Georgia
Power, and Savannah Electric cases have been stayed since the spring of 2001,
pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
appeal of a very similar New Source Review enforcement action against the
Tennessee Valley Authority (TVA). The TVA case involves many of the same legal
issues raised by the actions against Alabama Power, Georgia Power, and Savannah
Electric. Because the outcome of the TVA case could have a significant adverse
impact on Alabama Power and Georgia Power, both companies are parties to that
case as well. The U.S. District Court in Alabama has indicated that it will
revisit the issue of a continued stay in April 2002. The U.S. District Court in
Georgia is currently considering a motion by the EPA to reopen the Georgia case.
Georgia Power and Savannah Electric have opposed that motion.

   The Company believes that it has complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place.

   An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

Retail Revenue Sharing Plan

In early 1999, the FPSC staff and the Company became involved in discussions
primarily related to reducing the Company's authorized rate of return. On
October 1, 1999, the Office of Public Counsel, the Coalition for Equitable
Rates, the Florida Industrial Power Users Group, and the Company jointly filed a
petition to resolve the issues. The stipulation included a reduction to retail
base rates of $10 million annually and provided for revenues to be shared within
set ranges for 1999 through 2002. Customers receive two-thirds of any revenue
within the sharing range and the Company retains one-third. Any revenue above
this range is refunded to the customers. The stipulation also included
authorization for the Company, at its discretion, to accrue up to an additional
$5 million to the property insurance reserve and $1 million to amortize a
regulatory asset related to the corporate office. The Company also filed a
request to prospectively reduce its authorized return on equity (ROE) range from
11 to 13 percent to 10.5 to 12.5 percent in order to help ensure that the FPSC
would approve the stipulation. The FPSC approved both the stipulation and the
ROE request with an effective date of November 4, 1999.

   The Company's retail revenue range for sharing was $358 million to $374
million in calendar year 2001, and $352 million to $368 million in 2000, to be
shared between the Company and its retail customers on the one-third/two-thirds
basis. Actual retail revenues in 2001 were $360.3 million and $362.4 million in
2000. The Company recorded revenues subject to refund of $1.5 million in 2001
and $6.9 million in 2000. The estimated refund with interest was $0.03 million
in 2001 and $0.3 million in 2000 and was reflected in customer billings in
February 2002 and 2001 respectively. In addition to the refund, the Company
amortized $1 million of the regulatory assets related to the corporate office in
2001 and 2000, and accrued an additional $1.0 million to the property insurance


                                     II-140



<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


reserve in 2001. For calendar year 2002, there are specified sharing ranges for
each month from the expected in-service date of Smith Unit 3 until the end of
the year. The sharing plan will expire at the earlier of the in-service date of
Smith Unit 3 or December 31, 2002.

Retail Rate Case

On September 10, 2001, the Company filed a request with the FPSC for a base rate
increase of approximately $70 million, the majority of which is needed to
recover costs related to the Smith Unit 3 combined cycle facility currently
under construction and scheduled to be placed in service by June 2002. Hearings
are scheduled for February 25 through March 1, 2002 with a decision expected in
early May 2002 and new rates effective June 6, 2002.

4. COMMITMENTS

Construction Program

The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $103 million in 2002, $72 million in 2003, and
$107 million in 2004. The construction program is subject to periodic review and
revision, and actual construction costs may vary from the above estimates
because of numerous factors. These factors include changes in business
conditions; revised load growth estimates; changes in environmental regulations;
increasing costs of labor, equipment, and materials; and cost of capital. At
December 31, 2001, significant purchase commitments were outstanding in
connection with the construction program. The Company has budgeted $24.3 million
in 2002 as the remaining cost of a 574 megawatt combined cycle gas generating
unit to be located in the eastern portion of its service area. The unit is
expected to have an in-service date of June 2002. The Company's remaining
construction program is related to maintaining and upgrading the transmission,
distribution, and generating facilities.

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into contract commitments for the procurement of fuel. In
some cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Total estimated obligations at
December 31, 2001 were as follows:

   Year                                           Fuel
   ---------                                 ----------------
                                              (in millions)
   2002                                                 $140
   2003                                                  109
   2004                                                  112
   2005                                                  113
   2006                                                  115
   2007-2025                                             398
   ----------------------------------------------------------
   Total commitments                                    $987
   ==========================================================

   In addition, SCS acts as agent for the five operating companies and Southern
Power with regard to natural gas purchases. Natural gas purchases (in dollars)
are based on various indices at the actual time of delivery; therefore, only the
volume commitments are firm. The Company's committed volumes are allocated based
on usage projections as of December 31 as follows:

   Year                                        Natural Gas
   ---------                                 ----------------
                                                 (MMBtu)
   2002                                       14,194,988
   2003                                       28,377,592
   2004                                       15,071,438
   2005                                        6,913,093
   2006                                        4,187,658
   2007 and thereafter                         1,676,250
   ------------------------------------------------------
   Total commitments                          70,421,019
   ======================================================

   Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.

Lease Agreements

In 1989, the Company and Mississippi Power jointly entered into a twenty-two
year operating lease agreement for the use of 495 aluminum railcars. In 1994, a
second lease agreement for the use of 250 additional aluminum railcars was
entered into for twenty-two years. Both of these leases are for the
transportation of coal to Plant Daniel. At the end of each lease term, the
Company has the option to purchase the 745 railcars at the greater of lease
termination value or fair market value, or to renew the leases at the end of the
lease term.

                                     II-141


<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


   The Company, as a joint owner of Plant Daniel, is responsible for one half of
the lease costs. The lease costs are charged to fuel inventory and are allocated
to fuel expense as the fuel is used. The Company's share of the lease costs
charged to fuel inventories was $1.9 million in 2001 and $2.4 million in 2000.
The annual amounts for 2002 through 2006 are expected to be $1.9 million, $1.9
million, $1.9 million, $2.0 million, and $2.0 million, respectively, and after
2006 are expected to total $11.7 million.

5.  JOINT OWNERSHIP AGREEMENTS

The Company and Mississippi Power jointly own Plant Daniel Unit No. 1 and Unit
No. 2.  Plant Daniel is a generating plant located in Jackson County,
Mississippi. In accordance with the operating agreement, Mississippi Power
acts as the Company's agent with respect to the construction, operation, and
maintenance of these units.

   The Company and Georgia Power jointly own Plant Scherer Unit No. 3. Plant
Scherer is a generating plant located near Forsyth, Georgia. In accordance with
the operating agreement, Georgia Power acts as the Company's agent with respect
to the construction, operation, and maintenance of the unit.

   The Company's pro rata share of expenses related to both plants is included
in the corresponding operating expense accounts in the Statements of Income.

   At December 31, 2001, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:

                                         Plant          Plant
                                        Scherer      Daniel Unit
                                       Unit No. 3     Nos. 1 & 2
                                      (coal-fired)   (coal-fired)
                                     -----------------------------
                                            (in thousands)
Plant In Service                       $184,901(1)    $228,278
Accumulated Depreciation                $73,684       $120,646
Construction Work in Progress           $1,556          $6,174

Nameplate Capacity (2)
   (megawatts)                             205             500
Ownership                                   25%             50%
------------------------------------------------------------------

(1)  Includes net plant acquisition adjustment.
(2)  Total megawatt nameplate capacity:
       Plant Scherer Unit No. 3:  818
       Plant Daniel Unit Nos. 1&2:  1,000

6.  LONG-TERM POWER SALES AGREEMENTS

The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity to certain non-affiliated utilities located
outside the system's service area. The unit power sales agreements are firm and
pertain to capacity related to specific generating units. Because the energy is
generally sold at cost under these agreements, profitability is primarily
affected by revenues from capacity sales. The capacity revenues from these sales
were $19.5 million in 2001, $20.3 million in 2000, and $19.8 million in 1999.

   Unit power from specific generating plants of Southern Company is currently
being sold to Florida Power Corporation (FPC), Florida Power & Light Company
(FP&L), and Jacksonville Electric Authority (JEA). Under these agreements, 210
megawatts of net dependable capacity were sold by the Company during 2001. Sales
will remain close to that level, unless reduced by FP&L, FPC, and JEA with a
minimum of three years notice, until the expiration of the contracts in 2010.

7.  INCOME TAXES

At December 31, 2001, the tax-related regulatory assets to be recovered from
customers were $16.8 million. These assets are attributable to tax benefits
flowed through to customers in prior years and to taxes applicable to
capitalized allowance for funds used during construction. At December 31, 2001,
the tax-related regulatory liabilities to be credited to customers were $28.3
million. These liabilities are attributable to deferred taxes previously
recognized at rates higher than current enacted tax law and to unamortized
investment tax credits.

   Details of the federal and state income tax provisions are as follows:

                                     2001       2000        1999
                                ----------------------------------
                                          (in thousands)
Total provision for income taxes:
Federal--
   Current                        $24,207    $37,250     $33,973
   Deferred                         2,568    (11,159)     (6,107)
                                   26,775     26,091      27,866
------------------------------------------------------------------
State--
   Current                          3,701      5,796       5,267
   Deferred                           826     (1,357)       (502)
                                    4,527      4,439       4,765
------------------------------------------------------------------
Total                             $31,302    $30,530     $32,631
==================================================================

                                     II-142


<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


   The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:

                                                2001            2000
                                          ---------------------------
                                                (in thousands)
Deferred tax liabilities:
   Accelerated depreciation                 $179,071        $172,646
   Other                                      27,328          14,262
---------------------------------------------------------------------
Total                                        206,399         186,908
---------------------------------------------------------------------
Deferred tax assets:
   Federal effect of state deferred taxes      9,009           8,703
   Postretirement benefits                     9,379           9,205
   Other                                      17,881          14,742
---------------------------------------------------------------------
Total                                         36,269          32,650
---------------------------------------------------------------------
Net deferred tax liabilities                 170,130         154,258
Less current portion, net                     (8,162)           (816)
---------------------------------------------------------------------
Accumulated deferred income
   taxes in the Balance Sheets              $161,968         $155,074
=====================================================================

   Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation and amortization in the Statements of Income. Credits amortized in
this manner amounted to $1.7 million in 2001 and $1.9 million in each of 2000
and 1999. At December 31, 2001, all investment tax credits available to reduce
federal income taxes payable had been utilized.

   A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                       2001     2000     1999
                                    ---------------------------
Federal statutory rate                   35%      35%      35%
State income tax,
   net of federal deduction               4        4        4
Non-deductible book
   depreciation                           1        1        1
Difference in prior years'
   deferred and current tax rate         (2)      (2)      (2)
Other, net                               (3)      (1)       -
---------------------------------------------------------------
Effective income tax rate                35%      37%      38%
===============================================================

   The Company and the other subsidiaries of Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each subsidiary's current and deferred tax expense is computed on a
stand-alone basis. In accordance with Internal Revenue Service regulations, each
company is jointly and severally liable for the tax liability.

8.  CAPITALIZATION

Preferred Securities

In January 1997, Gulf Power Capital Trust I (Trust I), of which the Company owns
all of the common securities, issued $40 million of 7.625 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust I are
$41 million aggregate principal amount of the Company's 7.625 percent junior
subordinated notes due December 31, 2036.

   In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company
owns all of the common securities, issued $45 million of 7.0 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust II are
$46 million aggregate principal amount of the Company's 7.0 percent junior
subordinated notes due December 31, 2037.

   In November 2001, Gulf Power Capital Trust III (Trust III), of which the
Company owns all of the common securities, issued $30 million of 7.375 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust III are $31 million aggregate principal amount of the Company's 7.375
percent junior subordinated notes due September 30, 2041.

   The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of payment obligations with respect to the preferred
securities of Trust I, Trust II, and Trust III. Trust I, Trust II, and Trust III
are subsidiaries of the Company, and accordingly are consolidated in the
Company's financial statements.

Securities Due Within One Year

At December 31, 2001, the Company had an improvement fund requirement of
$550,000. The first mortgage bond improvement fund requirement amounts to 1
percent of each outstanding series of bonds authenticated under the indenture
prior to January 1 of each year, other than those issued to collateralize
pollution control revenue bond obligations. The requirement may be satisfied by
depositing cash, reacquiring bonds, or by pledging additional property equal to
1 and 2/3 times the requirement.

   The sinking fund requirements of first mortgage bonds were satisfied by
certifying property additions in 2001 and 2000. It is anticipated that the 2002


                                     II-143


<PAGE>
NOTES (continued)
Gulf Power Company 2001 Annual Report


requirement will be satisfied by certifying property additions. Sinking fund
requirements and/or maturities through 2006 applicable to long-term debt are as
follows: none in 2002; $60.6 million in 2003; $50.6 million on 2004; none in
2005; and $37.6 million in 2006.

Dividend Restrictions

The Company's first mortgage bond indenture contains various common stock
dividend restrictions, which remain in effect as long as the bonds are
outstanding. At December 31, 2001, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.

Bank Credit Arrangements

At December 31, 2001, the Company had $41.5 million of lines of credit with
banks subject to renewal June 1 of each year, of which $41.5 million remained
unused. In addition, the Company has two unused committed lines of credit
totaling $61.9 million that were established for liquidity support of its
variable rate pollution control bonds. In connection with these credit lines,
the Company has agreed to pay commitment fees and/or to maintain compensating
balances with the banks. The compensating balances, which represent
substantially all of the cash of the Company except for daily working funds and
like items, are not legally restricted from withdrawal.

   The Company borrows through commercial paper programs that have the liquidity
support of committed bank credit arrangements. In addition, the Company from
time to time borrows under uncommitted lines of credit with banks. The amount of
commercial paper outstanding at December 31, 2001 was $37.4 million.

   In addition, the Company has bid-loan facilities with five major money center
banks that total $110 million, of which $50 million was committed at December
31, 2001.

Assets Subject to Lien

The Company's mortgage, which secures the first mortgage bonds issued by the
Company, constitutes a direct first lien on substantially all of the Company's
fixed property and franchises.

9.  QUARTERLY FINANCIAL DATA (Unaudited)

Summarized quarterly financial data for 2001 and 2000 are as follows:

                                                         Net Income
                                                    After Dividends
                         Operating     Operating       on Preferred
Quarter Ended             Revenues        Income              Stock
--------------------------------------------------------------------
                                     (in thousands)
March 2001                $165,029       $24,785            $10,196
June 2001                  180,430        30,702             14,770
September 2001             226,616        45,504             26,657
December 2001              153,128        16,268              6,684

March 2000                $138,498       $16,007             $4,653
June 2000                  182,120        30,505             12,927
September 2000             232,533        52,614             26,438
December 2000              161,168        20,755              7,825
--------------------------------------------------------------------

   The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.


                                     II-144


<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Gulf Power Company 2001 Annual Report


---------------------------------------------------------------------------------------------------------------------------------
                                                            2001            2000            1999            1998            1997
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>             <C>             <C>             <C>             <C>
Operating Revenues (in thousands)                       $725,203        $714,319        $674,099        $650,518        $625,856
Net Income after Dividends
  on Preferred Stock (in thousands)                      $58,307         $51,843         $53,667         $56,521         $57,610
Cash Dividends
on Common Stock (in thousands)                           $53,275         $59,000         $61,300         $57,200         $64,600
Return on Average Common Equity (percent)                  12.51           12.20           12.63           13.20           13.33
Total Assets (in thousands)                           $1,569,517      $1,312,064      $1,308,495      $1,267,901      $1,265,612
Gross Property Additions (in thousands)                 $274,668         $95,807         $69,798         $69,731         $54,289
---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                     $504,894        $427,378        $422,313        $427,652        $428,718
Preferred stock                                            4,236           4,236           4,236           4,236          13,691
Company obligated mandatorily
  redeemable preferred securities                        115,000          85,000          85,000          85,000          40,000
Long-term debt                                           467,784         365,993         367,449         317,341         296,993
---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)         $1,091,914        $882,607        $878,998        $834,229        $779,402
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                         46.2            48.4            48.0            51.3            55.0
Preferred stock                                              0.4             0.5             0.5             0.5             1.8
Company obligated mandatorily
  redeemable preferred securities                           10.5             9.6             9.7            10.2             5.1
Long-term debt                                              42.9            41.5            41.8            38.0            38.1
---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)              100.0           100.0           100.0           100.0           100.0
=================================================================================================================================
Security Ratings:
First Mortgage Bonds -
   Moody's                                                    A1              A1              A1              A1              A1
   Standard and Poor's                                        A+              A+             AA-             AA-             AA-
   Fitch                                                      A+             AA-             AA-             AA-             AA-
Preferred Stock -
   Moody's                                                  Baa1              a2              a2              a2              a2
   Standard and Poor's                                      BBB+            BBB+              A-               A               A
   Fitch                                                      A-               A               A              A+              A+
Unsecured Long-Term Debt -
   Moody's                                                    A2              A2              A2              A2              A2
   Standard and Poor's                                         A               A               A               A               A
   Fitch                                                       A              A+              A+              A+              A+
=================================================================================================================================
Customers (year-end):
Residential                                              327,128         321,731         315,240         307,077         300,257
Commercial                                                48,654          47,666          47,728          46,370          44,589
Industrial                                                   270             280             267             257             267
Other                                                        468             442             316             268             264
---------------------------------------------------------------------------------------------------------------------------------
Total                                                    376,520         370,119         363,551         353,972         345,377
=================================================================================================================================
Employees (year-end):                                      1,309           1,327           1,339           1,328           1,328
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                                              II-145



<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Gulf Power Company 2001 Annual Report


--------------------------------------------------------------------------------------------------------------------------------
                                                           2001            2000            1999            1998            1997
--------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S>                                                   <C>              <C>            <C>             <C>             <C>
Residential                                           $ 313,165        $302,210       $ 279,238       $ 279,621       $ 276,924
Commercial                                              188,759         177,047         167,305         163,207         163,751
Industrial                                               81,719          74,095          68,222          71,119          77,045
Other                                                       948          (4,712)          2,184           2,113           2,077
--------------------------------------------------------------------------------------------------------------------------------
Total retail                                            584,591         548,640         516,949         516,060         519,797
Sales for resale  - non-affiliates                       82,252          66,890          62,354          61,893          63,697
Sales for resale  - affiliates                           27,256          66,995          66,110          42,642          16,760
--------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity                694,099         682,525         645,413         620,595         600,254
Other revenues                                           31,104          31,794          28,686          29,923          25,602
--------------------------------------------------------------------------------------------------------------------------------
Total                                                  $725,203        $714,319        $674,099        $650,518        $625,856
================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential                                           4,716,404       4,790,038       4,471,118       4,437,558       4,119,492
Commercial                                            3,417,427       3,379,449       3,222,532       3,111,933       2,897,887
Industrial                                            2,018,206       1,924,749       1,846,237       1,833,575       1,903,050
Other                                                    21,208          18,730          19,296          18,952          18,101
--------------------------------------------------------------------------------------------------------------------------------
Total retail                                         10,173,245      10,112,966       9,559,183       9,402,018       8,938,530
Sales for resale  - non-affiliates                    2,093,203       1,705,486       1,561,972       1,341,990       1,531,179
Sales for resale  - affiliates                          962,892       1,916,526       2,511,983       1,758,150         848,135
--------------------------------------------------------------------------------------------------------------------------------
Total                                                13,229,340      13,734,978      13,633,138      12,502,158      11,317,844
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                                6.64            6.31            6.25            6.30            6.72
Commercial                                                 5.52            5.24            5.19            5.24            5.65
Industrial                                                 4.05            3.85            3.70            3.88            4.05
Total retail                                               5.75            5.43            5.41            5.49            5.82
Sales for resale                                           3.58            3.70            3.15            3.37            3.38
Total sales                                                5.25            4.97            4.73            4.96            5.30
Residential Average Annual
  Kilowatt-Hour Use Per Customer                         14,497          14,992          14,318          14,577          13,894
Residential Average Annual
  Revenue Per Customer                                  $962.57         $945.87         $894.18         $918.56         $933.99
Plant Nameplate Capacity
Ratings (year-end) (megawatts)                            2,188           2,188           2,188           2,188           2,174
Maximum Peak-Hour Demand (megawatts):
Winter                                                    2,106           2,154           2,085           2,040           1,844
Summer                                                    2,223           2,285           2,161           2,146           2,032
Annual Load Factor (percent)                               57.5            55.4            55.2            55.3            55.5
Plant Availability Fossil-Steam (percent):                 90.1            85.2            87.2            87.6            91.0
--------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                       81.2            87.8            89.8            89.2            87.1
Oil and gas                                                 1.0             1.6             2.5             2.0             0.4
Purchased power -
  From non-affiliates                                       6.5             7.6             5.9             5.5             3.5
  From affiliates                                          11.3             3.0             1.8             3.3             9.0
--------------------------------------------------------------------------------------------------------------------------------
Total                                                     100.0           100.0           100.0           100.0           100.0
================================================================================================================================
</TABLE>






                                                              II-146

<PAGE>

                           MISSISSIPPI POWER COMPANY
                               FINANCIAL SECTION

                                      II-147
<PAGE>


MANAGEMENT'S REPORT
Mississippi Power Company 2001 Annual Report


The management of Mississippi Power Company has prepared -- and is responsible
for -- the financial statements and related information included in this report.
These statements were prepared in accordance with accounting principles
generally accepted in the United States and necessarily include amounts that are
based on the best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.

    The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.

    The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.

    The audit committee of the board of directors, composed of four independent
directors, provides a broad overview of management's financial reporting and
control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.

    Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.

    In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Mississippi Power Company in conformity with accounting principles generally
accepted in the United States.




/s/Michael D. Garrett
Michael D. Garrett
President and Chief Executive Officer


/s/Michael W. Southern
Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer

February 13, 2002



                                      II-148
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANT


To Mississippi Power Company:

We have audited the accompanying balance sheets and statements of capitalization
of Mississippi Power Company (a Mississippi corporation and a wholly owned
subsidiary of Southern Company) as of December 31, 2001 and 2000, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

    We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

    In our opinion, the financial statements (pages II-160 through II-176)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

    As explained in Note 1 to the financial statements, effective January 1,
2001, Mississippi Power Company changed its method of accounting for derivative
instruments and hedging activities.




/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002



                                      II-149
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 2001 Annual Report


RESULTS OF OPERATIONS

Earnings

Mississippi Power Company's 2001 net income after dividends on preferred stock
of $63.9 million increased $8.9 million over 2000 earnings of $55.0 million,
which were $0.2 million more than 1999 earnings of $54.8 million. Net income for
2001 was higher due to additional sales for resale primarily attributable to the
commercial operation of the new Plant Daniel Combined Cycle Units 3 and 4 and
lower interest expense.

Revenues

Operating revenues for the Company in 2001 and the changes from the prior year
are as follows:
                                            Increase (Decrease)
                              Amount          From Prior Year
                              ------         ----------------
                               2001          2001          2000
                            ---------------------------------------
                                         (in thousands)
  Retail --
    Base Revenues             $284,255    $  (3,000)     $  (4,343)
    Fuel cost recovery
      and other                204,898       (6,398)        33,460
  -----------------------------------------------------------------
  Total retail                 489,153       (9,398)        29,117
  -----------------------------------------------------------------
  Sales for resale --
    Non-affiliates             204,623        58,692         14,927
    Affiliates                  85,652        57,737          8,469
  -----------------------------------------------------------------
  Total sales for resale       290,275       116,429         23,396
  Other operating
     revenues                   16,637         1,432          2,085
  -----------------------------------------------------------------
  Operating revenues          $796,065      $108,463       $ 54,598

  =================================================================
  Percent change                               15.8%          8.6%
  -----------------------------------------------------------------

    Total retail revenues for 2001 decreased approximately 1.9 percent when
compared to 2000. The decrease resulted primarily from lower energy sales to
residential, commercial, and industrial customers as a result of mild weather
and a slowdown in manufacturing activity in the Company's service territory.
Retail revenues for 2000 reflected a 6.2 percent increase over the prior year
due to the continued growth in the service area, increased fuel revenues, and a
positive weather impact.

    Fuel revenues generally represent the direct recovery of fuel expense
including purchased power. Therefore, changes in recoverable fuel expenses are
offset with corresponding changes in fuel revenues and have no effect on net
income.

    Sales for resale to non-affiliates are influenced by those utilities' own
customer demand, plant availability, and the cost of their predominant fuels.
Included in sales for resale to non-affiliates are revenues from rural electric
cooperative associations and municipalities located in southeastern Mississippi.
Energy sales to these customers decreased 3.7 percent in 2001 and increased 10.9
percent in 2000, with the related revenues decreasing 2.4 percent and rising
10.8 percent, respectively. The customer demand experienced by these utilities
is determined by factors very similar to those of the Company. Revenues from
other sales outside the service area increased in 2001 when compared to 2000 as
a result of a new long term contract made possible by the commercial operation
of Plant Daniel Units 3 and 4.

    Energy sales to affiliated companies within the Southern Company electric
system, as well as purchases, will vary from year to year depending on demand
and the availability and cost of generating resources at each company. These
sales do not have a significant impact on earnings.

    Below is a breakdown of kilowatt-hour sales for 2001 and the percent change
for the last two years:

                           2001               Percent Change
                       -------------    ---------------------------
                            KWH              2001         2000
                        (in millions)   ---------------------------
 Residential               2,163            (5.4)%         1.7%
 Commercial                2,841            (1.5)          1.3
 Industrial                4,276            (2.3)         (0.7)
 Other                        40            (0.3)          2.5
                       -------------
 Total retail              9,320            (2.8)          0.5
 Sales for
    Resale --
     Non-affiliates        5,011            36.4          12.9
     Affiliates            2,953           552.3         (16.2)
                       -------------
 Total                    17,284            26.0           2.8
 ==================================================================

    Residential sales decreased 5.4 percent due to unusually mild weather in the
Company's service area. Commercial sales decreased 1.5 percent and industrial
sales fell 2.3 percent due to an economic slowdown. Total retail kilowatt-hour
sales increased slightly in 2000. This increase primarily resulted from the
continued growth in the service area, increased tourism, and the positive impact
of weather. Kilowatt-hour sales from outside the service area increased in 2001
when compared to 2000 as a result of a new contract made possible by the


                                      II-150
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


commercial operation of Plant Daniel Combined Cycle Units 3 and 4. Again, sales
to affiliates will vary year to year depending on demand and cost of generating
resources at each company.

Expenses

Total operating expenses were $663 million in 2001, reflecting an increase of
$98 million or 17.4 percent over the prior year. The increase was due primarily
to the commercial operation of Plant Daniel Combined Cycle Units 3 and 4. In
2000, total operating expenses increased by 10.1 percent over the prior year due
primarily to higher fuel and purchased power expenses.

    Fuel costs are the single largest expense for the Company. Fuel expenses for
2001 and 2000 increased 45.4 percent and 10.7 percent, respectively. The
increase for 2001 was due to increased generation especially from Plant Daniel
Combined Cycle Units 3 and 4 and a higher average cost of fuel. The 2000
increase was due to increased generation and a higher average cost of fuel.

    In 2001, expenses related to purchased power from non-affiliates decreased
26.4 percent, while expenses related to purchased power from affiliates
increased 5.7 percent which, in total, resulted in a 11.1 percent decrease when
compared to 2000. This decrease in purchased power is primarily due to the
commercial operation of Plant Daniel Combined Cycle Units 3 and 4 and the
expiration of non-affiliated purchase power contracts in 2000. Sales and
purchases among the Company and its affiliates will vary from period to period
depending on demand and the availability and variable production cost of each
generating unit in the Southern Company electric system.

    The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:

                                        2001     2000      1999
                                    ----------------------------
Total generation
 (millions of kilowatt hours)         15,770   11,688    11,599
Sources of generation
 (percent) --
    Coal                                  59       83        81
    Gas                                   41       17        19
Average cost of fuel per net
 kilowatt-hour generated
         (cents) --                     1.89     1.80      1.65
----------------------------------------------------------------

    Other operation expenses increased 17.2 percent in 2001 primarily due to an
increase in other production expenses due to the commercial operation of Plant
Daniel Combined Cycle Units 3 and 4. In 2000, other operation expense decreased
8.2 percent primarily due to a decrease in administrative and general expenses.
Maintenance expense in 2001 increased primarily due to the commercial operation
of Plant Daniel Combined Cycle Units 3 and 4, while maintenance expense in 2000
increased primarily due to additional scheduled maintenance. Depreciation and
amortization expense increased 7.6 percent in 2001 due to a growth in plant
investment and the amortization of the Company's regulatory asset related to its
Environmental Compliance Overview Plan (ECO Plan). In 2000, depreciation expense
increased slightly due to growth in plant investment and new depreciation rates,
which became effective January 2000.

    Taxes other than income taxes decreased 7.6 percent in 2001 due to reduced
ad valorem taxes related to a change in the tax rate. These taxes increased 1.7
percent in 2000 due to higher municipal franchise taxes resulting from higher
retail revenues. Interest on long-term debt decreased in 2001 as a result of
lower interest rates on debt outstanding.

Effects of Inflation

The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical costs does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.

Future Earnings Potential

General

The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of the Company's

                                     II-151
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


future earnings depends on numerous factors ranging from weather to energy sales
growth to a less regulated and more competitive environment. Expenses are
subject to constant review and cost control programs. The Company is also
maximizing the utility of invested capital and minimizing the need for
additional capital by refinancing outstanding obligations, managing the size of
its fuel stockpile, raising generating plant availability and efficiency, and
aggressively controlling its construction budget.

    The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
southeastern Mississippi. Prices for electricity provided by the Company to
retail customers are set by the Mississippi Public Service Commission (MPSC)
under cost-based regulatory principles. The Federal Energy Regulatory Commission
(FERC) regulates the Company's wholesale rate schedules, power sales contracts,
and transmission facilities.

    Operating revenues will be affected by any changes in rates under the
Performance Evaluation Plan (PEP) -- the Company's performance based ratemaking
plan -- and the ECO Plan. PEP has proven to be a stabilizing force on electric
rates, with only moderate changes in rates taking place. The ECO Plan provides
for recovery of costs (including costs of capital) associated with environmental
projects approved by the MPSC, most of which are required to comply with Clean
Air Act Amendments of 1990 (Clean Air Act) and the regulations thereunder. The
ECO Plan is operated independently of PEP. Compliance costs related to the Clean
Air Act could affect earnings if such costs cannot be recovered. The Company
filed its 2001 ECO Plan in January 2001 which was approved, as filed, by the
Mississippi PSC on March 7, 2001, and resulted in a slight increase in customer
prices. The Company filed its 2002 ECO Plan in January 2002, which, if approved
as filed, will result in a slight increase in rates. See Note 3 to the financial
statements under "Litigation and Regulatory Matters" for additional information.
The Clean Air Act and other important environmental items are discussed later
under "Environmental Matters."

    In August 2001, the Company filed a request with the MPSC for a retail rate
increase of approximately $46 million. In order to consider the Company's
request, the MPSC suspended the semi-annual evaluations under PEP. In December
2001, after a full investigation and hearing on the Company's request, the MPSC
approved an increase of approximately $39 million, which took effect in January
2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual
evaluations under PEP, beginning in February 2003 for the year 2002. PEP will
remain in effect until the MPSC modifies, suspends, or terminates the plan. The
MPSC also set for hearing in 2002 a review of the return on equity models used
in PEP in setting the Company's authorized return on equity. This proceeding
will conclude in 2002, so that changes to the PEP return on equity models, if
any, may be incorporated into the February 2003 PEP evaluation filing for the
period ending December 31, 2002. The outcome of this matter and any future
impact to the Company cannot now be determined.

    In February 2002, the Company reached an agreement with certain of its
wholesale customers to increase its wholesale tariff rates effective June 2002.
The agreement results in an annual increase of approximately $10.5 million and
the adoption of an Energy Cost Management clause similar to the one approved by
the Company's retail jurisdiction (see Note 1 to the financials). In addition,
the Company and its customers agreed that neither party would seek a unilateral
change to the new rates prior to December 31, 2003, except for changes due to
the operation of the fuel adjustment and energy cost management clauses. The
Company and its customers will file the agreement with the FERC for its
approval. Though the FERC has accepted settlement agreements as filed in the
past, the ultimate outcome of this matter before the FERC cannot now be
determined.

    In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash pension
income of approximately $3.2 million in 2001. Future pension income is dependent
on several factors including trust earnings and changes to the plan. For the
Company, pension income is a component of the regulated rates and does not have
a significant effect on net income. For more information, see Note 2 to the
financial statements.

    The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.

                                     II-152
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


    Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. The Clean Air Act and other important environmental items are
discussed later under "Environmental Matters."

    Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. These factors include weather,
competition, changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, and the rate of
economic growth in the Company's service area. The Company anticipates somewhat
slower growth in energy sales as the tourism industry stabilizes within its
service area. In addition to tourism, the healthcare and retail trade sectors
will provide most of the anticipated energy growth for the commercial class of
customers, while shipbuilding, chemicals, and the U.S. government will provide
much of the basis for anticipated growth in the industrial sector.

Industry Restructuring

The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows
independent power producers (IPPs) to access a utility's transmission network in
order to sell electricity to other utilities. This enhances the incentive for
IPPs to build cogeneration plants for a utility's large industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are affected by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers.

    Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
various stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. In May 2000, the MPSC ordered that its docket reviewing restructuring of
the electric industry in the State of Mississippi be suspended. The MPSC found
that retail competition may not be in the public interest at this time, and
ordered that no further formal hearings would be held on this subject. It found
that the current regulatory structure produced reliable low cost power and
"should not be changed without clear and convincing demonstration that change
would be in the public interest." The MPSC will continue to monitor retail and
wholesale restructuring activities throughout the United States and reserves its
right to order further formal hearings on the matter should new evidence
demonstrate that retail competition would be in the public interest and all
customers could receive a reduction in the total cost of their electric service.
If the MPSC decides to hold future restructuring hearings on this matter,
enactment would require numerous issues to be resolved, including significant
ones relating to recovery of any stranded investments, full cost recovery of
energy produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states have either discontinued or
delayed implementation of initiatives involving retail deregulation.

    Continuing to be a low-cost producer could provide significant opportunities
to increase market share and profitability in markets that evolve with changing
regulation. Conversely, unless the Company remains a low-cost producer and
provides quality service, the Company's energy sales growth could be limited,
and this could significantly erode earnings.

    In December 1999, the FERC issued its final ruling on Regional Transmission
Organizations (RTOs). The order encourages utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company and its operating companies,
including the Company, have submitted a series of status reports informing the
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing a for-profit RTO known
as SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. While the creation of SeTrans is not
expected to have a material impact on the Company's financial statements, the
outcome of this matter cannot now be determined.


                                     II-153
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


Accounting Policies

Critical Policies

The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of the Company's operation is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.

    Additionally, the Company accounts for its lease agreement with Escatawpa
Funding, Limited Partnership (Escatawpa) as an operating lease. Under this
agreement, Escatawpa, a special purpose entity, is owner-lessor of the
combined-cycle generating units at the Company's Plant Daniel. The Company does
not consolidate this entity since parties unrelated to the Company have made
substantive residual equity capital investments in excess of 3 percent. The FASB
has recently issued a draft interpretation that addresses issues related to
identifying and accounting for certain special purpose entities. One proposed
change would increase the 3 percent outside equity requirement to 10 percent.
This interpretation is in draft form; therefore, final conclusions may differ
from the draft. However, a change to a ten percent equity requirement could
result in the Company having to change its accounting for this lease agreement,
including having to consolidate the leased asset and related debt. See Note 4 to
the financial statements where the lease agreement and the Company's related
obligations are discussed.

New Accounting Standards

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on the Company's net income in 2001 was not material. An
additional interpretation of Statement No. 133 will result in a change -
effective April 1, 2002 - in accounting for certain contracts related to fuel
supplies that contain quantity options. These contracts will be accounted for as
derivatives and marked to market. However, due to the existence of the Company's
cost-based fuel recovery clause, this change is not expected to have a material
impact on net income.

   In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No.142 in January 2002 with no material
impact on the financial statements.

   Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.


FINANCIAL CONDITION

Overview

The principal change in the Company's financial condition during 2001 was the
addition of approximately $61 million to utility plant. Funding for these


                                      II-154
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


additions and other capital requirements were derived primarily from operations.
The Statements of Cash Flows provide additional details.

Credit Rating Risk

The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are certain fixed-price physical gas purchase contracts that
could require collateral - but not accelerated payment - in the event of a
credit rating change to below investment grade; however, at December 31, 2001,
this exposure was immaterial.

Exposure to Market Risks

Due to cost-based rate regulations, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market. Realized gains and losses
are recognized in the income statements as incurred. At December 31, 2001,
exposure from these activities was not material to the Company's financial
statements. Also, based on the Company's overall variable rate long-term debt
exposure at December 31, 2001, a near-term 100 basis point change in interest
rates would not materially affect the Company's financial statements. Fair value
of changes in energy trading contracts and year-end valuations are as follows:

                                                   Changes
                                               During the Year
                                           ----------------------
                                                 Fair Value
 ----------------------------------------------------------------
                                               (in thousands)
Contracts beginning of year                     $    112
Contracts realized or settled                       (101)
New contracts at inception                             -
Changes in valuation techniques                        -
Current period changes                            (3,841)
-----------------------------------------------------------------
Contracts end of year                           $ (3,830)
=================================================================

                                       Source of Year-End
                                        Valuation Prices
                              -----------------------------------
                                                   Maturity
                                 Total       --------------------
                               Fair Value    Year 1     1-3 Years
-----------------------------------------------------------------
                                         (in thousands)
-----------------------------------------------------------------
Actively quoted                 $(3,830)    $(3,517)    $ (313)
External sources                      -           -          -
Models and other  methods
                                      -           -          -
-----------------------------------------------------------------
Contracts end of year           $(3,830)    $(3,517)    $ (313)
=================================================================

    For additional information, see Note 1 to the financial statements under
"Financial Instruments."

    In June 2001, the MPSC approved the Company's request to implement an Energy
Cost Management Clause (ECM). ECM, among other things, allows the Company to
utilize financial instruments to hedge its fuel commitments. Amounts paid or
received as a result of the use of these instruments are recognized as fuel
related expense and are recovered or credited through the ECM factor calculated
annually and applied to customer billings. The Company records the fair value of
these financial instruments (cash flow hedges) in its financial statements in
accordance with FASB Statement No. 133 with a related regulatory asset or
liability recorded under the provisions of FASB Statement No. 71.

    As of December 31, 2001, the Company had financial instruments related to
natural gas commodity contracts that had a contract value of approximately $31
million and $30 million expiring in 2002 and 2003, respectively. The market
values as of December 31, 2001 for these contracts were approximately $27
million and $30 million, respectively. The amounts settled and recognized in the
financial statements for 2001 were not material. Currently, the Company does not
have any fixed price natural gas commitments, either physical or financial,
beyond 2003.

Sources of Capital

To meet short-term cash needs and contingencies, the Company had at December 31,
2001 approximately $18.9 million of cash and cash equivalents and approximately
$114.5 million of unused committed credit agreements.

    The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.

                                     II-155


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


At December 31, 2001, the Company had outstanding $16 million of commercial
paper.

    It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from sources similar to those used in the past. These sources were primarily the
issuance of first mortgage bonds and preferred securities, in addition to
pollution control revenue bonds issued for the Company's benefit by public
authorities. The Company also utilized unsecured debt and lease arrangements in
the past as well.

    The Company has no restrictions on the amounts of unsecured indebtedness it
may incur. However, the Company is required to meet certain coverage
requirements specified in its mortgage indenture and corporate charter to issue
new first mortgage bonds and preferred stock. The Company's coverage ratios are
high enough to permit, at present interest rate levels, any foreseeable security
sales. The amount of securities which the Company will be permitted to issue in
the future will depend upon market conditions and other factors prevailing at
that time.

Financing Activity

In May 2001, the Company received a $70 million capital contribution which was
used to retire $35 million of 6.60 percent first mortgage bonds, $20 million of
series C variable-rate senior notes, and $15 million in short term debt. The
Company plans to continue, to the extent possible, a program to retire
higher-cost debt and replace these securities with lower-cost capital. See the
Statements of Cash Flows for further details.

    Composite financing rates decreased for the year 2001 when compared to 2000
and 1999. As of year-end, the composite rates were as follows:

                                   2001       2000      1999
                                -------------------------------
 Composite interest rate on
   long-term debt                 4.60%      6.41%     6.19%

 Composite preferred stock
   dividend rate                  6.33%      6.33%     6.33%

 Composite interest rate on
   preferred securities           7.75%      7.75%     7.75%
 --------------------------------------------------------------

Off-Balance Sheet Financing Arrangements

In 1999, the Company signed an Agreement for Lease and a Lease Agreement with
Escatawpa. These agreements called for the Company to design and construct, as
agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility at the
Company's Plant Victor J. Daniel Facility (Facility). In May 2001, the Facility
was completed and placed into commercial operation. Effective with commercial
operation of the Facility, the initial 10-year lease term under its lease
arrangement for the Facility with Escatawpa began. The completion cost was
approximately $370 million. The lease provides for a residual value guarantee
(approximately 71% of the completion cost) by the Company that is due upon
termination of the lease in certain circumstances. The lease also includes
purchase and renewal options. Upon termination of the lease, at the Company's
option, the Company may either exercise its purchase option or the Facility can
be sold to a third party. The Company expects that the fair market value of the
leased Facility would substantially reduce or eliminate the Company's payment
under the residual value guarantee. In 2001, the Company recognized
approximately $18 million in lease expense. See Note 4 to the financial
statements for additional information.

Capital Structure

At year-end 2001, the Company's ratio of common equity to total capitalization,
excluding long-term debt due within one year, increased from 48.1 percent in
2000 to 62.1 percent. The Company plans to replace the long-term debt due within
one year with new issues.

Capital Requirements for Construction

The Company's projected construction expenditures for the next three years total
$241 million ($84 million in 2002, $72 million in 2003, and $85 million in
2004). The major emphasis within the construction program will be on the upgrade
of existing facilities.

    Revisions to projected construction expenditures may be necessary because of
factors such as changes in business conditions, revised load projections, the
availability and cost of capital, changes in environmental regulations, and
alternatives such as leasing.




                                     II-156
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


Other Capital Requirements

In addition to the funds required for the Company's construction program,
approximately $115 million will be required by the end of 2003 for present
sinking fund requirements and maturities of long-term debt. The Company plans to
continue, when economically feasible, to retire higher cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.

    These capital requirements, lease obligations, and purchase commitments -
discussed in notes 4 and 8 to the financial statements - are as follows:

                               2002       2003        2004
 ----------------------------------------------------------
                                  (in thousands)
Bonds -
    First mortgage          $     -   $     -     $     -
    Pollution control            20        25          25
Notes                        80,000    35,000           -
Lease obligations            27,000    27,000      27,000
Purchase commitments
    Fuel                    225,000   188,000       7,000
    Purchased power               -         -           -
-----------------------------------------------------------

    At the beginning of 2002, the Company had not used any of its available
credit arrangements. Credit arrangements are as follows:

                                           Expires
                               -----------------------------
 Total          Unused          2002          2003 & Beyond
------------------------------------------------------------
                         (in millions)
 $114.5         $114.5        $109.5             5.0
------------------------------------------------------------

Environmental Matters

On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action in the U.S. District Court against Alabama Power Company, Georgia Power
Company, and the system service company. The complaint alleges violations of the
New Source Review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the operating companies a notice of violation related
to 10 generating facilities, which includes the five facilities mentioned
previously, and the Company's plants Watson and Greene County. In early 2000,
the EPA filed a motion to amend its complaint to add the violations alleged in
its notice of violation, and to add Gulf Power, Savannah Electric, and the
Company as defendants. The complaint and notice of violation are similar to
those brought against and issued to several other electric utilities. These
complaints and notices of violation allege that the utilities had failed to
secure necessary permits or install additional pollution control equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. The U.S. District Court in Georgia granted
Alabama Power's motion to dismiss for lack of jurisdiction in Georgia and
granted the system service company's motion to dismiss on the grounds that it
neither owned nor operated the generating units involved in the proceedings. The
court granted the EPA's motion to add Savannah Electric as a defendant, but it
denied the motion to add Gulf Power and the Company based on lack of
jurisdiction over those companies. The court directed the EPA to re-file its
amended complaint limiting claims to those brought against Georgia Power and
Savannah Electric. The EPA re-filed those claims as directed by the court. Also,
the EPA re-filed its claims against Alabama Power in U.S. District Court in
Alabama. It has not re-filed against Gulf Power, the system service company, or
the Company.

     The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.

     The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit. Prior to January 30, 1997, the penalty was

                                      II-157
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


$25,000 per day. An adverse outcome of this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates.

    In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act -- the acid rain compliance
provision of the law -- significantly affected Southern Company. Reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
were required in two phases. Phase I compliance began in 1995.

    Southern Company achieved Phase I compliance at its affected plants by
primarily switching to low-sulfur coal and with some equipment upgrades.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $65 million for the Company.

    Phase II sulfur dioxide compliance was required in 2000. Southern Company
used emission allowances and fuel switching to comply with Phase II
requirements. Also, equipment to control nitrogen oxide emissions was installed
on additional system fossil-fired units as necessary to meet Phase II limits and
ozone non-attainment requirements for metropolitan Atlanta through 2000. Phase
II compliance did not have a material impact on the Company.

    The Company's ECO Plan is designed to allow recovery of costs of compliance
with the Clean Air Act, as well as other environmental statutes and regulations.
The MPSC reviews environmental projects and the Company's environmental policy
through the ECO Plan. Under the ECO Plan, any increase in the annual revenue
requirement is limited to 2 percent of retail revenues. The Company's management
believes that the ECO Plan provides for recovery of the Clean Air Act costs. See
Note 3 to the financial statements under "Environmental Compliance Overview
Plan" for additional information.

    A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.

    In July 1997, the EPA revised the national ambient air quality standards for
ozone and fine particulate matter. This revision made the standards
significantly more stringent. In the subsequent litigation of these standards,
the U.S. Supreme Court found the EPA's implementation program for the new ozone
standard unlawful and remanded it to the EPA. In addition, the Federal District
of Columbia Circuit Court of Appeals is considering other legal challenges to
these standards. A court decision is expected in the spring of 2002. If the
standards are eventually upheld, implementation could be required by 2007 to
2010.

    In September 1998, the EPA issued regional nitrogen oxide reduction rules to
the states for implementation. Compliance is required by May 31, 2004 for most
states including Alabama. For Georgia, further rulemaking was required, and
proposed compliance was delayed until May 1, 2005. The final rules affect 21
states that do not include Mississippi. The EPA is presently evaluating whether
or not to bring an additional 15 states including Mississippi, under this
regional nitrogen oxide rule.

    In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act, and the regulations are scheduled to be finalized by the end
of 2004 with implementation to take place around 2007. In January 2001, the EPA
proposed guidance for the determination of Best Available Retrofit Technology
(BART) emission controls under the Regional Haze Regulations. Installation of
BART controls is expected to take place in 2010. Litigation of the Regional Haze
Regulations, including the BART provisions, is ongoing in the Federal District
of Columbia Circuit Court of Appeals. A court decision is expected in mid-2002.

    Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and


                                      II-158
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2001 Annual Report


standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.

    In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.

    The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.

    The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties currently or
previously owned. Upon identifying potential sites, the Company conducts
studies, when possible, to determine the extent of any required cleanup. Should
remediation be determined to be probable, reasonable estimates of costs to clean
up such sites are developed and recognized in the financial statements.

    Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; and the Endangered
Species Act. Changes to these laws could affect many areas of the Company's
operations. The full impact of any such changes cannot be determined at this
time.

    Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if any
-- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.

Cautionary Statement Regarding Forward-Looking
Information

This Annual Report includes forward-looking statements in addition to historical
information. Forward-looking information includes, among other things,
statements concerning projected sales growth and scheduled completion of new
generation. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
"anticipates," "believes," "estimates," "predicts," "projects," "potential," or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action against the Company; the effects, extent and timing of the entry of
additional competition in the markets of the Company; the impact of fluctuations
in commodity prices, interest rates, and customer demand; state and federal rate
regulations; political, legal, and economic conditions and developments in the
United States; internal restructuring or other restructuring options that may be
pursued; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or beneficial
to the Company; the effects of, and changes in, economic conditions in the areas
in which the Company operates; the direct or indirect effects on the Company's
business resulting from the terrorist incidents on September 11, 2001, or any
similar such incidents or responses to such incidents; financial market
conditions and the results of financing efforts; the timing and acceptance of
the Company's new product and service offerings; the ability of the Company to
obtain additional generating capacity at competitive prices; weather and other
natural phenomena; and other factors discussed elsewhere herein and in other
reports (including Form 10-K) filed from time to time by the Company with the
Securities and Exchange Commission.


                                     II-159

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Mississippi Power Company 2001 Annual Report

--------------------------------------------------------------------------------------------------------------
                                                                2001                 2000                1999
--------------------------------------------------------------------------------------------------------------
                                                                          (in thousands)
Operating Revenues:
<S>                                                         <C>                  <C>                 <C>
Retail sales                                                $489,153             $498,551            $469,434
Sales for resale --
  Non-affiliates                                             204,623              145,931             131,004
  Affiliates                                                  85,652               27,915              19,446
Other revenues                                                16,637               15,205              13,120
--------------------------------------------------------------------------------------------------------------
Total operating revenues                                     796,065              687,602             633,004
--------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel                                                         277,946              191,127             172,686
Purchased power --
  Non-affiliates                                              41,254               56,082              40,080
  Affiliates                                                  53,990               51,057              31,007
Other                                                        134,845              115,055             125,291
Maintenance                                                   56,153               52,750              47,085
Depreciation and amortization                                 54,077               50,275              49,206
Taxes other than income taxes                                 44,966               48,686              47,893
--------------------------------------------------------------------------------------------------------------
Total operating expenses                                     663,231              565,032             513,248
--------------------------------------------------------------------------------------------------------------
Operating Income                                             132,834              122,570             119,756
Other Income (Expense):
Interest income                                                  369                  347                 189
Other, net                                                      (532)                (647)              1,675
--------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                    132,671              122,270             121,620
--------------------------------------------------------------------------------------------------------------
Interest Expense and Other:
Interest expense, net                                         23,568               28,101              27,969
Distributions on preferred securities of subsidiary            2,712                2,712               2,712
--------------------------------------------------------------------------------------------------------------
Total interest charges and other, net                         26,280               30,813              30,681
--------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                 106,391               91,457              90,939
Income taxes                                                  40,533               34,356              34,117
--------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of                          65,858               57,101              56,822
   Accounting Change
Cumulative effect of accounting change--
  less income taxes of $43 thousand                               70                    -                   -
--------------------------------------------------------------------------------------------------------------
Net Income                                                    65,928               57,101              56,822
Dividends on Preferred Stock                                   2,041                2,129               2,013
--------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock               $ 63,887             $ 54,972            $ 54,809
==============================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>




                                                              II-160
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Mississippi Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------
                                                                         2001                 2000                1999
-----------------------------------------------------------------------------------------------------------------------
                                                                                   (in thousands)
Operating Activities:
<S>                                                                  <C>                  <C>                 <C>
Net income                                                           $ 65,928             $ 57,101            $ 56,822
Adjustments to reconcile net income
 to net cash provided from operating activities --
      Depreciation and amortization                                    58,105               54,638              53,427
      Deferred income taxes and investment tax credits, net            (9,718)                 752              (4,143)
      Other, net                                                        2,441               (1,747)              5,531
      Changes in certain current assets and liabilities --
         Receivables, net                                              (7,796)              (3,231)            (39,304)
         Fossil fuel stock                                            (20,269)              14,577              (9,379)
         Materials and supplies                                        (1,529)              (1,056)             (1,903)
         Accounts payable                                              53,462                1,309               1,391
         Other                                                         11,251                2,952              14,206
-----------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                           151,875              125,295              76,648
-----------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                              (61,193)             (81,211)            (75,888)
Other                                                                  (2,988)              (9,153)              1,009
-----------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                (64,181)             (90,364)            (74,879)
-----------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                             (40,027)              (1,500)             44,500
Proceeds --
   Other long-term debt                                                     -              100,000              59,400
   Capital contributions from parent company                           73,095               12,659               2,028
Retirements --
   First mortgage bonds                                               (36,000)                   -                   -
   Other long-term debt                                               (21,021)             (81,405)            (50,456)
   Preferred stock                                                          -                    -                   -
Payment of preferred stock dividends                                   (2,041)              (2,129)             (2,013)
Payment of common stock dividends                                     (50,200)             (54,700)            (56,100)
Other                                                                     (81)                (498)               (282)
-----------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities                                (76,275)             (27,573)             (2,923)
-----------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                11,419                7,358              (1,154)
Cash and Cash Equivalents at Beginning of Period                        7,531                  173               1,327
-----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                           $ 18,950              $ 7,531                $173
=======================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
   Interest (net of amount capitalized)                               $28,126              $30,570             $25,486
   Income taxes (net of refunds)                                       45,761               33,276              39,729
-----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
</TABLE>






                                                              II-161
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report

-------------------------------------------------------------------------------------------------------------------------
Assets                                                                                     2001                     2000
-------------------------------------------------------------------------------------------------------------------------
                                                                                                  (in thousands)
Current Assets:
<S>                                                                                  <C>                      <C>
Cash and cash equivalents                                                            $   18,950               $    7,531
Receivables --
  Customer accounts receivable                                                           63,286                   72,064
  Other accounts and notes receivable                                                    26,068                   21,843
  Affiliated companies                                                                   22,569                   10,071
  Accumulated provision for uncollectible accounts                                         (856)                    (571)
Fossil fuel stock, at average cost                                                       31,489                   11,220
Materials and supplies, at average cost                                                  23,223                   21,694
Other                                                                                    16,002                    8,320
-------------------------------------------------------------------------------------------------------------------------
Total current assets                                                                    200,731                  152,172
-------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service                                                                            1,741,499                1,665,879
Less accumulated provision for depreciation                                             698,681                  652,891
-------------------------------------------------------------------------------------------------------------------------
                                                                                      1,042,818                1,012,988
Construction work in progress                                                            38,253                   60,951
-------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                                  1,081,071                1,073,939
-------------------------------------------------------------------------------------------------------------------------
Other Property and Investments                                                            1,900                    2,268
-------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes                                                 13,394                   13,860
Prepaid pension costs                                                                     4,501                      434
Debt expense, being amortized                                                             4,396                    4,628
Premium on reacquired debt, being amortized                                               6,719                    7,168
Other                                                                                    20,821                   14,312
-------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                                  49,831                   40,402
-------------------------------------------------------------------------------------------------------------------------
Total Assets                                                                         $1,333,533               $1,268,781
=========================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>






                                                              II-162
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                                     2001                     2000
-----------------------------------------------------------------------------------------------------------------------
                                                                                                (in thousands)
Current Liabilities:
<S>                                                                              <C>                       <C>
Securities due within one year                                                       $  80,020               $       20
Notes payable                                                                           15,973                   56,000
Accounts payable --
  Affiliated                                                                             6,175                   10,715
  Other                                                                                105,834                   48,146
Customer deposits                                                                        6,540                    5,274
Taxes accrued --
  Income taxes                                                                          14,981                    8,769
  Other                                                                                 35,282                   36,799
Interest accrued                                                                         5,079                    4,482
Vacation pay accrued                                                                     5,810                    5,701
Other                                                                                   11,483                    6,473
-----------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                              287,177                  182,379
-----------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                           233,753                  370,511
-----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes                                                      138,913                  139,909
Deferred credits related to income taxes                                                23,626                   25,603
Accumulated deferred investment tax credits                                             22,268                   23,481
Employee benefits provisions                                                            31,041                   28,911
Workforce reduction plan                                                                 8,263                    9,734
Other                                                                                   30,003                   16,546
-----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                           254,114                  244,184
-----------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
  securities of subsidiary trust holding company junior
  subordinated notes (See accompanying statements)                                      35,000                   35,000
-----------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements)                                           31,809                   31,809
-----------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                              491,680                  404,898
-----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                          $1,333,533               $1,268,781
=======================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>





                                                               II-163

<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                                   2001              2000             2001              2000
-----------------------------------------------------------------------------------------------------------------------------
                                                                        (in thousands)                (percent of total)
Long-Term Debt:
First mortgage bonds --
       Maturity                           Interest Rates
       --------                           -------------
       <S>                               <C>                  <C>                  <C>               <C>               <C>
       June 1, 2023                       7.45%                $ 34,000          $ 35,000
       March 1, 2004                      6.60%                       -            35,000
       December 1, 2025                   6.875%                 30,000            30,000
-----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                       64,000           100,000
-----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
       6.05% due May 1, 2003                                     35,000            35,000
       6.75% due June 30, 2038                                   52,178            53,179
       Adjustable rates (2.0056% at 1/1/02)
       due 2000-2002                                             80,000           100,000
-----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable                                   167,178           188,179
-----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
     Pollution control revenue bonds --
       Collateralized:
        5.65% to 5.80% due 2007-2023                             26,745            26,765
      Non-collateralized:
        Variable rates (1.90% to 2.00% at 1/1/02)
         due 2020-2028                                           56,820            56,820
-----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                       83,565            83,585
-----------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net                           (970)           (1,233)
-----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $14.5 million)                                   313,773           370,531
Less amount due within one year                                  80,020                20
-----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year            $233,753          $370,511            29.5%             43.9%
-----------------------------------------------------------------------------------------------------------------------------

</TABLE>




                                                               II-164


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2001 and 2000
Mississippi Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------------
                                                                   2001              2000             2001              2000
-----------------------------------------------------------------------------------------------------------------------------
                                                                         (in thousands)               (percent of total)
<S>                                                           <C>                 <C>              <C>               <C>
Company Obligated Mandatorily
  Redeemable Preferred Securities:(Note 8)
$25 liquidation value --
  7.75%                                                        $ 35,000          $ 35,000
-----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million)          35,000            35,000              4.4               4.2
-----------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value
  4.40% to 7.00%                                                 31,809            31,809
-----------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $2.0 million)              31,809            31,809              4.0               3.8
-----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
  Authorized  - 1,130,000 shares
  Outstanding - 1,121,000 shares in 2001 and 2000                37,691            37,691
  Paid-in capital                                               267,256           194,161
  Premium on preferred stock                                        326               326
Retained earnings                                               186,407           172,720
-----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                               491,680           404,898             62.1              48.1
-----------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                           $792,242          $842,218           100.0%            100.0%
=============================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>




                                                              II-165
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Mississippi Power Company 2001 Annual Report

---------------------------------------------------------------------------------------------------------------------------
                                                                               Premium on
                                                    Common         Paid-In      Preferred      Retained
                                                     Stock         Capital        Stock        Earnings          Total
---------------------------------------------------------------------------------------------------------------------------
                                                                             (in thousands)

<S>                                                <C>             <C>            <C>               <C>         <C>
Balance at January 1, 1999                          $37,691        $179,474          $326        $173,740         $391,231
Net income after dividends on preferred stock             -               -             -          54,809           54,809
Capital contributions from parent company                 -           2,028             -               -            2,028
Cash dividends on common stock                            -               -             -         (56,100)         (56,100)
---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                         37,691         181,502           326         172,449          391,968
Net income after dividends on preferred stock             -               -             -          54,972           54,972
Capital contributions from parent company                 -          12,659             -               -           12,659
Cash dividends on common stock                            -               -             -         (54,700)         (54,700)
Other                                                     -               -             -              (1)              (1)
---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000                         37,691         194,161           326         172,720          404,898
Net income after dividends on preferred stock             -               -             -          63,887           63,887
Capital contributions from parent company                 -          73,095             -               -           73,095
Cash dividends on common stock                            -               -             -         (50,200)         (50,200)
---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001                        $37,691        $267,256          $326        $186,407         $491,680
===========================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>




                                                              II-166

<PAGE>
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2001 Annual Report


1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

Mississippi Power Company is a wholly owned subsidiary of Southern Company,
which is the parent company of five operating companies, a system service
company, Southern Communications Services (Southern LINC), Southern Nuclear
Operating Company (Southern Nuclear), Southern Power Company (Southern Power),
and other direct and indirect subsidiaries. The operating companies -- Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company, and Savannah Electric and Power Company -- provide electric service in
four southeastern states. Contracts among the operating companies -- related to
jointly owned generating facilities, interconnecting transmission lines, and the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission. The system
service company provides, at cost, specialized services to Southern Company and
subsidiary companies. Southern LINC provides digital wireless communications
services to the operating companies and also markets these services to the
public within the Southeast. Southern Nuclear provides services to Southern
Company's nuclear power plants. Southern Power was established in 2001 to
construct, own, and manage Southern Company's competitive generation assets and
sell electricity at market-based rates in the wholesale market.

    Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both the Company and its subsidiaries are
subject to the regulatory provisions of the PUHCA. The Company is also subject
to regulation by the FERC and the Mississippi Public Service Commission (MPSC).
The Company follows accounting principles generally accepted in the United
States and complies with the accounting policies and practices prescribed by the
respective commissions. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the
use of estimates, and the actual results may differ from those estimates.

    Prior years' data presented in the financial statements have been
reclassified to conform with the current year presentation.

Affiliate Transactions

The Company has an agreement with the system service company under which the
following services are rendered to the Company at cost: general and design
engineering, purchasing, accounting and statistical, finance and treasury, tax,
information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures, and other services with
respect to business and operations and power pool operations. Costs for these
services amounted to $44.1 million, $46.2 million, and $45.5 million during
2001, 2000, and 1999, respectively.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:

                                             2001         2000
                                       -------------------------
                                             (in thousands)
Deferred income tax charges              $ 13,394     $ 13,860
Vacation pay                                5,810        5,701
Premium on reacquired debt                  6,719        7,168
Fuel commitments                            4,328            -
Property damage reserve                    (4,044)      (3,519)
Deferred income tax credits               (23,626)     (25,603)
Other, net                                 (1,066)        (505)
----------------------------------------------------------------
Total                                    $  1,515     $ (2,898)
================================================================


                                     II-167
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


    In the event that a portion of the Company's operations is no longer subject
to the provisions of FASB Statement No. 71, the Company would be required to
write off related regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.

Revenues and Fuel Costs

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Mississippi and to wholesale customers in the Southeast.

    Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. The Company's retail and wholesale
rates include provisions to adjust billings for fluctuations in fuel costs, the
energy component of purchased power costs, and certain other costs. Retail rates
also include provisions to adjust billings for fluctuations in costs for ad
valorem taxes, certain qualifying environmental costs, and energy cost
management activities. Revenues are adjusted for differences between actual
allowable amounts and the amounts included in rates.

    The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts continued to average less than 1 percent of revenues.

Depreciation

Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.5 percent in 2001, 3.5
percent in 2000, and 3.3 percent in 1999. When property subject to depreciation
is retired or otherwise disposed of in the normal course of business, its
original cost -- together with the cost of removal, less salvage -- is charged
to accumulated depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
Depreciation expense includes an amount for the expected cost of removal of
facilities.

Income Taxes

The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. Original cost
includes: materials; labor; minor items of property; appropriate administrative
and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the estimated cost of funds used during construction, if
applicable. The cost of maintenance, repairs, and replacement of minor items of
property is charged to maintenance expense except for the maintenance of coal
cars and a portion of the railway track maintenance, which are charged to fuel
stock. The cost of replacements of property -- exclusive of minor items of
property -- is capitalized.

Cash and Cash Equivalents

For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.

Financial Instruments

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The 2001 impact
on net income was immaterial. The Company uses derivative financial instruments
to hedge exposure to fluctuations in interest rates and certain commodity
prices. Gains and losses on qualifying hedges are deferred and recognized either
as income or as an adjustment to the carrying amount of the hedged item when the
transaction occurs. The Company is exposed to losses related to financial
instruments in the event of counterparties' nonperformance. The Company has
established controls to determine and monitor the creditworthiness of
counterparties in order to mitigate the Company's exposure to counterparty
credit risk.

    The Company and its affiliates, through the system service company acting as
their agent, enters into commodity related forward and option contracts to limit


                                     II-168
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


exposure to changing prices on certain fuel purchases and electricity purchases
and sales. Substantially all of these bulk energy purchases and sales contracts
meet the definition of a derivative under FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities. In many cases, these fuel and
electricity contracts qualify for normal purchase and sale exceptions under
Statement No. 133 and are accounted for under the accrual method. Other
contracts qualify as cash flow hedges of anticipated transactions, resulting in
the deferral of related gains and losses, and are recorded in other
comprehensive income until the hedged transactions occur. Any ineffectiveness is
recognized currently in net income. Contracts that do not qualify for the normal
purchase and sale exception and that do not meet the hedge requirements are
marked to market through current period income.

    In June 2001, the MPSC approved the Company's request to implement an Energy
Cost Management Clause (ECM). ECM, among other things, allows the Company to
utilize financial instruments that are used to hedge its fuel commitments.
Amounts paid or received as a result of financial settlement of these
instruments are classified as fuel expense and are included in the ECM factor
applied to customer billings. The Company records the fair value of these
financial instruments (cash flow hedges) in its financial statements in
accordance with FASB Statement No. 133 with a related regulatory asset or
liability recorded under the provisions of FASB Statement No. 71.

    As of December 31, 2001, the Company had financial instruments related to
natural gas commodity contracts that had a contract value of approximately $31
million and $30 million expiring in 2002 and 2003, respectively. The market
values as of December 31, 2001 for these contracts were approximately $27
million and $30 million, respectively. The amounts settled and recognized in the
financial statements for 2001 were not material. Currently, the Company does not
have any fixed price natural gas commitments, either physical or financial,
beyond 2003.

    The Company's other financial instruments for which the carrying amount did
not equal fair value at December 31 were as follows:

                                      Carrying        Fair
                                       Amount        Value
                                   ------------------------
                                           (in millions)
Long-term debt:
 At December 31, 2001                   $314          $309
 At December 31, 2000                   $371          $362
Capital trust preferred
  securities:
 At December 31, 2001                   $ 35          $ 35
 At December 31, 2000                   $ 35          $ 34
-----------------------------------------------------------

    The fair values for long-term debt and preferred securities were based on
either closing market price or closing price of comparable instruments.

Materials and Supplies

Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
used or installed.

Provision for Property Damage

The Company is self-insured for the cost of storm, fire, and other uninsured
casualty damage to its property, including transmission and distribution
facilities. As permitted by regulatory authorities, the Company accrues for the
cost of such damage by charging expense and crediting an accumulated provision.
The cost of repairing damage resulting from such events that individually exceed
$50 thousand is charged to the accumulated provision. In 1999, an order from the
MPSC increased the maximum Property Damage Reserve from $18 million to $23
million and allows an annual accrual of up to $4.6 million. In 2001, the Company
provided for such costs by charges to income of $2.5 million. In 2000 and 1999,
the Company provided for such costs by charges to income of $3.5 million and
$4.4 million, respectively. As of December 31, 2001, the accumulated provision
amounted to $4.0 million.

2.  RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all these employees may
become eligible for such benefits when they retire. The Company funds trusts to


                                     II-169
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


the extent deductible under federal income tax regulations or the extent
required by regulatory authorities. In late 2000, the Company adopted several
pension and postretirement benefits plan changes that had the effect of
increasing benefits to both current and future retirees. The measurement date
for plan assets and obligations is September 30 for each year.

Pension Plan

Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:

                                                    Projected
                                               Benefit Obligations
                                           --------------------------
                                                2001         2000
---------------------------------------------------------------------
                                                 (in thousands)
Balance at beginning of year                  $154,411      $148,657
Service cost                                     4,797         4,357
Interest cost                                   11,817        10,912
Benefits paid                                   (8,456)       (8,169)
Actuarial gain and employee
    transfers                                    1,268        (1,646)
Amendments                                       8,406           300
Other                                              (76)            -
---------------------------------------------------------------------
Balance at end of year                        $172,167      $154,411
=====================================================================

                                                   Plan Assets
                                           --------------------------
                                                2001         2000
---------------------------------------------------------------------
                                                 (in thousands)
Balance at beginning of year                  $256,648      $221,487
Actual return on plan assets                   (37,214)       39,737
Benefits paid                                   (7,850)       (7,593)
Employee transfers                                 (38)        3,017
---------------------------------------------------------------------
Balance at end of year                        $211,546      $256,648
=====================================================================

    The accrued pension costs recognized in the Balance Sheets were as follows:


                                               2001          2000
---------------------------------------------------------------------
                                                 (in thousands)
Funded status                                $  39,379    $ 102,238
Unrecognized transition obligation              (2,716)      (3,253)
Unrecognized prior service cost                 13,656        6,298
Unrecognized net gain                          (45,818)    (104,849)
---------------------------------------------------------------------
Prepaid asset recognized in the
    Balance Sheets                           $   4,501    $     434
=====================================================================

    Components of the pension plans' net periodic cost were as follows:

                               2001        2000         1999
---------------------------------------------------------------
                                      (in thousands)
Service Cost                 $  4,797    $  4,357     $  4,501
Interest cost                  11,818      10,912       10,025
Expected return on
    plan assets               (17,328)    (15,910)     (14,681)
Recognized net gain            (3,012)     (2,577)      (1,670)
Net amortization                  511          76           76
---------------------------------------------------------------
Net pension income           $ (3,214)   $ (3,142)    $ (1,749)
===============================================================

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:

                                             Accumulated
                                         Benefit Obligations
                                     ---------------------------
                                          2001          2000
----------------------------------------------------------------
                                            (in thousands)
Balance at beginning of year            $44,952       $45,390
Service cost                                922           830
Interest cost                             3,411         3,309
Benefits paid                            (2,918)       (2,628)
Actuarial gain and
    employee transfers                    3,256        (1,949)
Amendments                                1,900             -
 ----------------------------------------------------------------
Balance at end of year                  $51,523       $44,952
================================================================

                                             Plan Assets
                                     ---------------------------
                                          2001          2000
----------------------------------------------------------------
                                            (in thousands)
Balance at beginning of year            $17,843       $14,998
Actual return on plan assets             (1,888)        2,511
Employer contributions                    3,232         2,961
Benefits paid                            (2,918)       (2,627)
----------------------------------------------------------------
Balance at end of year                  $16,269       $17,843
================================================================


                                     II-170
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


    The accrued postretirement costs recognized in the Balance Sheets were as
follows:

                                               2001        2000
------------------------------------------------------------------
                                                (in thousands)
Funded status                                $(35,254)   $(27,109)
Unrecognized transition obligation              3,928       4,275
Unrecognized prior service cost                 1,821           -
Unrecognized net gain                             (40)     (6,632)
Fourth quarter contributions                    1,268       1,065
------------------------------------------------------------------
Accrued liability recognized in the
    Balance Sheets                           $(28,277)   $(28,401)
==================================================================

    Components of the postretirement plans' net periodic cost
were as follows:

                                   2001        2000        1999
------------------------------------------------------------------
                                          (in thousands)
Service cost                    $    922    $    830    $    981
Interest cost                      3,411       3,309       3,105
Expected return on
    plan assets                   (1,409)     (1,235)    $(1,100)
Transition obligation                346         346         346
Prior service cost                    80           -           -
Recognized net loss                  (38)          -           -
------------------------------------------------------------------
Net postretirement cost         $  3,312    $  3,250    $  3,332
==================================================================

    The weighted average rates assumed in the actuarial calculations
for both the pension plans and postretirement benefits plan were:

                                               2001       2000
 ---------------------------------------------------------------
 Discount                                      7.50%      7.50%
 Annual salary increase                        5.00       5.00
 Long-term return on plan assets               8.50       8.50
 ---------------------------------------------------------------

    An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010 and
remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:

                                       1 Percent      1 Percent
                                        Increase      Decrease
-----------------------------------------------------------------
                                            (in thousands)
Benefit obligation                       $4,037         $3,551
Service and interest costs                  314            273
-----------------------------------------------------------------

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $2.5
million, $2.3 million, and $2.2 million, respectively.

3. LITIGATION AND REGULATORY MATTERS

General

The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.

Environmental Litigation

On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power and the system service company. The complaint alleges violations of the
New Source Review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day.

     The EPA concurrently issued to the operating companies a notice of
violation related to 10 generating facilities, which includes the five
facilities mentioned previously, and the Company's plants Watson and Greene
County. In early 2000, the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation and to add Gulf Power, Savannah


                                     II-171
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


Electric and the Company as defendants. The complaint and notice of violation
are similar to those brought against and issued to several other electric
utilities. These complaints and notices of violation allege that the utilities
had failed to secure necessary permits or install additional pollution control
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. The U.S. District Court in
Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction and
granted the system service company's motion to dismiss on the grounds that it
neither owned nor operated the generating units involved in the proceedings. The
court granted the EPA's motion to add Savannah Electric as a defendant, but it
denied the motion to add Gulf Power and the Company based on lack of
jurisdiction over those companies. The court directed the EPA to re-file its
amended complaint limiting claims to those brought against Georgia Power and
Savannah Electric. The EPA re-filed those claims as directed by the court. Also,
the EPA re-filed its claims against Alabama Power in U.S. District Court in
Alabama. It has not re-filed against Gulf Power, the system service company, or
the Company.

     The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA case
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA case
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies are parties to that case as well. The U.S. District Court in Alabama
has indicated that it will revisit the issue of a continued stay in April 2002.
The U.S. District Court in Georgia is currently considering a motion by the EPA
to reopen the Georgia case. Georgia Power and Savannah Electric have opposed
that motion.

     The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and could possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates.

Retail Rate Adjustment Plans

The Company's retail base rates are set under a Performance Evaluation Plan
(PEP) approved by the MPSC in 1994. PEP was designed with the objective that the
plan would reduce the impact of rate changes on the customer and provide
incentives for the Company to keep customer prices low. PEP includes a mechanism
for rate adjustments based on the Company's ability to maintain low rates for
customers and on the Company's performance as measured by three indicators that
emphasize price and service to the customer. PEP provides for semiannual
evaluations of the Company's performance-based return on investment. Any change
in rates is limited to 2 percent of retail revenues per evaluation period.

     In August 2001, the Company filed a request with the MPSC for a retail rate
increase of approximately $46 million. In order to consider the Company's
request, the MPSC suspended the semi-annual evaluations under PEP. In December
2001, after a full investigation and hearing on the Company's request, the MPSC
approved an increase of approximately $39 million, which took effect in January
2002. Additionally, the MPSC ordered the Company to reactivate the semi-annual
evaluations under PEP, beginning in February 2003 for the year 2002. PEP will
remain in effect until the MPSC modifies, suspends, or terminates the plan. The
MPSC also set for hearing in 2002 a review of the return on equity models used
in PEP in setting the Company's authorized return on equity. This proceeding
will conclude in 2002, so that changes to the PEP return on equity models, if
any, may be incorporated into the February 2003 PEP evaluation filing for the
period ending December 31, 2002. The outcome of this matter and any future
impact to the Company cannot now be determined.

Environmental Compliance Overview Plan

The MPSC approved the Company's Environmental Compliance Overview Plan (ECO
Plan) in 1992. The ECO Plan establishes procedures to facilitate the MPSC's
overview of the Company's environmental strategy and provides for recovery of
costs (including costs of capital) associated with environmental projects
approved by the MPSC. Under the ECO Plan, any increase in the annual revenue


                                     II-172
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


requirement is limited to 2 percent of retail revenues. However, the ECO Plan
also provides for carryover of any amount over the 2 percent limit into the next
year's revenue requirement. The Company conducts studies, when possible, to
determine the extent of any required environmental remediation. Should such
remediation be determined to be probable, reasonable estimates of costs to clean
up such sites are developed and recognized in the financial statements. The
Company recovers such costs under the ECO Plan as they are incurred, as provided
for in the Company's 1995 ECO Plan Order. The Company filed its 2002 ECO Plan in
January, which, if approved as filed, will result in a slight increase in
customer prices.

Approval for New Capacity

In January 1998, the Company was granted a Certificate of Public Convenience and
Necessity by the MPSC to build approximately 1,064 megawatts of combined cycle
generation at the Company's Plant Daniel site, to be placed in service by June
2001. In December 1998, the Company requested approval to transfer the ownership
rights under the certificate to Escatawpa Funding, Limited Partnership
(Escatawpa), which will lease the facility to the Company (see Note 4,
Commitments). In September 2000, the Company and the Mississippi Public
Utilities Staff entered, and the MPSC in October 2000 approved, a new
stipulation that modifies a January 1999 stipulation and order covering cost
allocation. The 1999 stipulation and MPSC order would have excluded the new
capacity from retail rate base and would have assigned the Company's existing
generating facilities entirely to the retail jurisdiction. The new stipulation
and MPSC order allocates a pro-rata share of the new capacity along with the
Company's existing generating capacity to the retail jurisdiction. The Company's
2001 retail rate case reflected this methodology and the MPSC's December 2001
order on the retail rate case filing approved the Company's cost allocations.

4.  COMMITMENTS

Construction Program

The Company is engaged in continuous construction programs, the costs of which
are currently estimated to total $84 million in 2002, $72 million in 2003, and
$85 million in 2004. The construction program is subject to periodic review and
revision, and actual construction costs may vary from the above estimates
because of numerous factors. These factors include changes in business
conditions; revised load growth estimates; changes in environmental regulations;
increasing costs of labor, equipment and materials; and cost of capital.
Significant construction will continue related to transmission and distribution
facilities, and the upgrading of generating plants.

Lease Agreements

In 1989, the Company entered into a twenty-two year operating lease agreement
for the use of 495 aluminum railcars. In 1994, a second lease agreement for the
use of 250 additional aluminum railcars was also entered into for twenty-two
years. The Company has the option to purchase the 745 railcars at the greater of
lease termination value or fair market value, or to renew the leases at the end
of the lease term. Both of these leases were for the transport of coal to Plant
Daniel.

    Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible for
one half of the lease cost. The Company's share (50%) of the leases, charged to
fuel stock, was $1.9 million in 2001, $2.1 million in 2000, and $2.8 million in
1999. The Company's annual lease payments for 2002 through 2006 will average
approximately $2.0 million and after 2006, lease payments total in aggregate
approximately $12 million.

    In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding, Limited Partnership (Escatawpa). These agreements called
for the Company to design and construct, as agent for Escatawpa, a 1,064
megawatt natural gas combined cycle facility at the Company's Plant Victor J.
Daniel Facility (Facility). In May 2001, the Facility was completed and placed
into commercial operation. Effective with commercial operation of the Facility
at Plant Daniel, the initial 10-year lease term under its lease arrangement for
the Facility with Escatawpa began. The completion cost was approximately $370
million. The lease provides for a residual value guarantee (approximately 71% of
the completion cost) by the Company that is due upon termination of the lease in
certain circumstances. The lease also includes a purchase and renewal option.
Upon termination of the lease, at the Company's option, the Company may either
exercise its purchase option or the Facility can be sold to a third party. The
Company expects that the fair market value of the leased Facility would


                                     II-173
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


substantially reduce or eliminate the Company's payment under the residual value
guarantee. In 2001, the Company recognized approximately $18 million in lease
expense. The Company estimates that its annual amount of future minimum
operating lease payments, exclusive of any payment related to the residual value
guarantee, as of December 31, 2001, were as follows:

Year                                          Lease Payments
----                                          --------------
                                               (in millions)
2002                                               $26.4
2003                                                25.5
2004                                                25.2
2005                                                25.0
2006                                                24.7
2007 and thereafter                                143.0
----------------------------------------------------------
Total commitments                                 $269.8
==========================================================

Fuel

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fuel. In most cases, these contracts contain provisions for price escalations,
minimum production levels, and other financial commitments. In addition, the
Company utilizes financial instruments to eliminated price volatility. Total
estimated fixed-price obligations at December 31, 2001, were as follows:

Year                                               Fuel
----                                               ----
                                               (in millions)
2002                                               $225
2003                                                188
2004                                                  7
2005                                                  7
2006                                                  7
2007 and thereafter                                  86
----------------------------------------------------------
Total commitments                                  $520
==========================================================

    In addition, the system service company acts as agent for the five operating
companies and Southern Power with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various indices at the actual time of
delivery; therefore, only the volume commitments are firm. The Company's
committed volumes allocated based on usage projections, as of December 31, 2001
are as follows:


Year                                            Natural Gas
----                                            -----------
                                                  (MMBtu)
2002                                             40,345,416
2003                                             39,723,953
2004                                             22,521,216
2005                                             11,161,628
2006                                              8,044,570
2007 and thereafter                               2,981,474
------------------------------------------------------------
Total commitments                               124,778,257
============================================================

    Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.

5.  JOINT OWNERSHIP AGREEMENTS

The Company and Alabama Power own as tenants in common Units 1 and 2 at Plant
Greene County located in Alabama. Additionally, the Company and Gulf Power own
as tenants in common Units 1 and 2 at Plant Daniel located in Mississippi.

    At December 31, 2001, the Company's percentage ownership and investment in
these jointly owned facilities were as follows:

                                        Company's
    Generating       Total    Percent     Gross       Accumulated
       Plant       Capacity  Ownership  Investment   Depreciation
       -----       --------  ---------  ----------   ------------
                  (Megawatts)               (in thousands)
 Greene County
  Units 1 and 2       500       40%     $ 65,486       $ 35,116

 Daniel
  Units 1 and 2     1,000       50%     $236,979       $116,766
 --------------------------------------------------------------

    The Company's share of plant operating expenses is included in the
corresponding operating expenses in the Statements of Income.

 6. LONG-TERM CAPACITY SALES AND LEASE
    AGREEMENTS

The Company and the other operating companies of Southern Company have long-term
contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. Because the
energy is generally sold at cost under these agreements, profitability is
primarily affected by revenues from capacity sales. The Company's capacity
revenues under these agreements were not material during the periods reported.

                                      II-174
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


    In 1984, the Company and Entergy Corp. (formerly Gulf States Utilities)
entered into a 40-year transmission facilities agreement whereby Entergy began
paying a use fee to the Company covering all expenses relative to ownership and
operation and maintenance of a 500 kV line, including amortization of its
original $57 million cost. For the three years ended 2001, use fees collected
under this agreement, net of related expenses, amounted to approximately $2.7
million each year and are included within Other Income in the Statements of
Income.

    During 2000, the Company entered into a 10-year capacity lease that began in
mid 2001. The minimum capacity lease revenue that the Company will receive will
average approximately $21 million per year over the 10-year period. Capacity
revenues for 2001 were approximately $12.3 million and were classified as sales
for resale in the financial statements.

7.  INCOME TAXES

At December 31, 2001, the tax-related regulatory assets and liabilities were $13
million and $24 million, respectively. These assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized interest. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.

    Details of the federal and state income tax provisions are shown below:

                                    2001       2000        1999
                                ----------------------------------
                                          (in thousands)
 Total provision for
    income taxes
 Federal --
    Current                       $43,596     $28,934    $33,379
    Deferred                       (8,661)        622     (3,973)
 -----------------------------------------------------------------
                                   34,935      29,556     29,406
 -----------------------------------------------------------------
 State --
    Current                         6,698       4,670      4,881
    Deferred                       (1,057)        130       (170)
 -----------------------------------------------------------------
                                    5,641       4,800      4,711
 -----------------------------------------------------------------
 Total                            $40,576     $34,356    $34,117
 =================================================================

    The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities are as follows:

                                      2001              2000
                                 -------------------------------
                                          (in thousands)
 Deferred tax liabilities:
    Accelerated depreciation        $147,147          $151,278
    Basis differences                  8,271             8,559
    Other                             34,544            24,136
 ---------------------------------------------------------------
 Total                               189,962           183,973
 ---------------------------------------------------------------
 Deferred tax assets:
    Other property
     basis differences                15,983            17,147
    Pension and
     other benefits                    9,474             9,528
    Property insurance                 1,547             3,558
    Unbilled fuel                      5,596             5,727
    Other                             27,269             9,669
 ---------------------------------------------------------------
 Total                                59,869            45,629
 ---------------------------------------------------------------
 Total deferred tax
    liabilities, net                 130,093           138,344
 Portion included in current
    assets, net                        8,820             1,565
 ---------------------------------------------------------------
 Accumulated deferred
    income taxes in the
    Balance Sheets                  $138,913          $139,909
 ===============================================================

    Deferred investment tax credits are amortized over the lives of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $1.2 million in 2001, 2000, and 1999. At December 31, 2001, all
investment tax credits available to reduce federal income taxes payable had been
utilized.

    A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                    2001       2000       1999
                                 --------------------------------
 Federal statutory rate             35.0%      35.0%      35.0%
 State income tax, net of
    federal deduction                3.4        3.4        3.4
 Non-deductible book
    depreciation                     0.5        0.6        0.7
 Other                              (0.8)      (1.5)      (1.6)
 ----------------------------------------------------------------
 Effective income tax rate          38.1%      37.5%      37.5%
 ================================================================

    Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.


                                     II-175
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


8. CAPITALIZATION

Preferred Securities

In February 1997, Mississippi Power Capital Trust I (Trust I), of which the
Company owns all the common securities, issued $35 million of 7.75 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust I are $36 million aggregate principal amount of the Company's 7.75 percent
junior subordinated notes due February 15, 2037.

    The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trust's payment obligations with respect to the
preferred securities.

    Trust I is a subsidiary of the Company, and accordingly is consolidated in
the Company's financial statements.

Long-Term Debt Due Within One Year

A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year is as follows:

                                              2001       2000
                                           ---------------------
                                              (in thousands)
 Bond improvement fund requirement          $   650    $1,000
 Less: Portion to be satisfied by
       certifying property additions            650     1,000
 --------------------------------------------------------------
 Cash sinking fund requirement                    -         -
 Current portion of other long-term debt     80,000         -
 Pollution control bond cash
    sinking fund requirements                    20        20
 --------------------------------------------------------------
 Total                                      $80,020    $   20
 ==============================================================

    The first mortgage bond improvement fund requirement is one percent of each
outstanding series authenticated under the indenture of the Company prior to
January 1 of each year, other than first mortgage bonds issued as collateral
security for certain pollution control obligations. The requirement must be
satisfied by June 1 of each year by depositing cash or reacquiring bonds, or by
pledging additional property equal to 166-2/3 percent of such requirement.


Bank Credit Arrangements

At December 31, 2001, the Company had total committed credit agreements with
banks for approximately $114.5 million. At year-end 2001, the unused portion of
these committed credit agreements was approximately $114.5 million. These credit
agreements expire at various dates in 2002 and 2003. Some of these agreements
allow short-term borrowings to be converted into term loans, payable in 12 equal
quarterly installments, with the first installment due at the end of the first
calendar quarter after the applicable termination date or at an earlier date at
the Company's option. In connection with these credit arrangements, the Company
agrees to pay commitment fees based on the unused portions of the commitments or
to maintain compensating balances with the banks. The amount of commercial paper
outstanding at December 31, 2001 was $16 million.

Assets Subject to Lien

The Company's mortgage indenture dated as of September 1, 1941, as amended and
supplemented, which secures the first mortgage bonds issued by the Company,
constitutes a direct first lien on substantially all of the Company's fixed
property and franchises.

Dividend Restrictions

The Company's first mortgage bond indenture and the corporate charter contain
various common stock dividend restrictions. At December 31, 2001, approximately
$118 million of retained earnings was restricted against the payment of cash
dividends on common stock under the most restrictive terms of the mortgage
indenture or corporate charter.


                                     II-176
<PAGE>
NOTES (continued)
Mississippi Power Company 2001 Annual Report


9.  QUARTERLY FINANCIAL DATA
    (UNAUDITED)

Summarized quarterly financial data for 2001 and 2000 are as follows:

                                                       Net Income
                                                     After Dividends
                        Operating       Operating     On Preferred
    Quarter Ended        Revenues         Income          Stock
-------------------------------------------------------------------
                                     (in thousands)
March 2001               $171,312        $23,615        $  9,757
June 2001                 203,949         32,640          16,571
September 2001            235,916         53,263          30,379
December 2001             184,888         23,315           7,180

March 2000               $134,705        $18,593        $  6,722
June 2000                 176,028         28,130          12,232
September 2000            220,119         53,943          28,762
December 2000             156,750         21,904           7,256
-------------------------------------------------------------------

    The Company's business is influenced by seasonal weather conditions and the
timing of rate changes.



                                     II-177
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Mississippi Power Company 2001 Annual Report


--------------------------------------------------------------------------------------------------------------------------------
                                                           2001            2000            1999            1998            1997
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>             <C>             <C>             <C>             <C>
Operating Revenues (in thousands)*                     $796,065        $687,602        $633,004        $595,131        $543,588
Net Income after Dividends
  on Preferred Stock (in thousands)                     $63,887         $54,972         $54,809         $55,105         $54,010
Cash Dividends
  on Common Stock (in thousands)                        $50,200         $54,700         $56,100         $51,700         $49,400
Return on Average Common Equity (percent)                 14.25           13.80           14.00           14.15           14.00
Total Assets (in thousands)                          $1,333,533      $1,268,781      $1,251,136      $1,189,605      $1,166,829
Gross Property Additions (in thousands)                 $61,193         $81,211         $75,888         $68,231         $55,375
--------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                    $491,680        $404,898        $391,968        $391,231        $387,824
Preferred stock                                          31,809          31,809          31,809          31,809          31,896
Company obligated mandatorily
  redeemable preferred securities                        35,000          35,000          35,000          35,000          35,000
Long-term debt                                          233,753         370,511         321,802         292,744         291,665
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)          $792,242        $842,218        $780,579        $750,784        $746,385
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                        62.1            48.1            50.2            52.1            52.0
Preferred stock                                             4.0             3.8             4.1             4.2             4.3
Company obligated mandatorily
  redeemable preferred securities                           4.4             4.2             4.5             4.7             4.7
Long-term debt                                             29.5            43.9            41.2            39.0            39.0
--------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)             100.0           100.0           100.0           100.0           100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
  Moody's                                                   Aa3             Aa3             Aa3             Aa3             Aa3
  Standard and Poor's                                        A+              A+             AA-             AA-             AA-
  Fitch                                                     AA-             AA-             AA-             AA-             AA-
Preferred Stock -
  Moody's                                                    A3              a1              a1              a1              a1
  Standard and Poor's                                      BBB+            BBB+              A-               A               A
  Fitch                                                       A               A               A              A+              A+
Unsecured Long-Term Debt -
  Moody's                                                    A1               -               -               -               -
  Standard and Poor's                                         A               -               -               -               -
  Fitch                                                      A+               -               -               -               -
================================================================================================================================
Customers (year-end):
Residential                                             158,852         158,253         157,592         156,530         156,650
Commercial                                               32,538          32,372          31,837          31,319          31,667
Industrial                                                  498             517             546             587             642
Other                                                       173             206             202             200             200
--------------------------------------------------------------------------------------------------------------------------------
Total                                                   192,061         191,348         190,177         188,636         189,159
================================================================================================================================
Employees (year-end):                                     1,316           1,319           1,328           1,230           1,245
--------------------------------------------------------------------------------------------------------------------------------
* 1999 data includes the true-up of the unbilled revenue estimates.
</TABLE>







                                                              II-178
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Mississippi Power Company 2001 Annual Report


------------------------------------------------------------------------------------------------------------------------------------
                                                               2001            2000            1999            1998            1997
------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)*:
<S>                                                       <C>              <C>             <C>             <C>             <C>
Residential                                               $ 164,716        $170,729        $159,945        $157,642        $138,608
Commercial                                                  163,253         163,552         153,936         145,677         134,208
Industrial                                                  156,525         159,705         151,244         135,039         140,233
Other                                                         4,659           4,565           4,309           4,209           4,193
------------------------------------------------------------------------------------------------------------------------------------
Total retail                                                489,153         498,551         469,434         442,567         417,242
Sales for resale  - non-affiliates                          204,623         145,931         131,004         121,225         105,141
Sales for resale  - affiliates                               85,652          27,915          19,446          18,285          10,143
------------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity                    779,428         672,397         619,884         582,077         532,526
Other revenues                                               16,637          15,205          13,120          13,054          11,062
------------------------------------------------------------------------------------------------------------------------------------
Total                                                      $796,065        $687,602        $633,004        $595,131        $543,588
====================================================================================================================================
Kilowatt-Hour Sales (in thousands)*:
Residential                                               2,162,623       2,286,143       2,248,255       2,248,915       2,039,042
Commercial                                                2,840,840       2,883,197       2,847,342       2,623,276       2,407,520
Industrial                                                4,275,781       4,376,171       4,407,445       3,729,166       3,981,875
Other                                                        41,009          41,153          40,091          39,772          40,508
------------------------------------------------------------------------------------------------------------------------------------
Total retail                                              9,320,253       9,586,664       9,543,133       8,641,129       8,468,945
Sales for resale  - non-affiliates                        5,011,212       3,674,621       3,256,175       3,157,837       2,895,182
Sales for resale  - affiliates                            2,952,455         452,611         539,939         552,142         478,884
------------------------------------------------------------------------------------------------------------------------------------
Total                                                    17,283,920      13,713,896      13,339,247      12,351,108      11,843,011
====================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents)*:
Residential                                                    7.62            7.47            7.11            7.01            6.80
Commercial                                                     5.75            5.67            5.41            5.55            5.57
Industrial                                                     3.66            3.65            3.43            3.62            3.52
Total retail                                                   5.25            5.20            4.92            5.12            4.93
Sales for resale                                               3.64            4.21            3.96            3.76            3.42
Total sales                                                    4.51            4.90            4.65            4.71            4.50
Residential Average Annual
  Kilowatt-Hour Use Per Customer *                           13,634          14,445          14,301          14,376          13,132
Residential Average Annual
  Revenue Per Customer *                                  $1,038.41       $1,078.76       $1,017.42       $1,007.68         $892.68
Plant Nameplate Capacity
Ratings (year-end) (megawatts)                                3,156           2,086           2,086           2,086           2,086
Maximum Peak-Hour Demand (megawatts):
Winter                                                        2,249           2,305           2,125           1,740           1,922
Summer                                                        2,466           2,593           2,439           2,339           2,209
Annual Load Factor (percent)                                   60.7            59.3            59.6            58.0            59.1
Plant Availability Fossil-Steam (percent):                     92.8            92.6            91.0            90.0            92.4
------------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                           52.0            67.8            69.4            66.5            70.5
Oil and gas                                                    35.9            13.5            15.9            14.5            12.5
Purchased power -
  From non-affiliates                                           3.1             7.7             6.2             8.0             3.0
  From affiliates                                               9.0            11.0             8.5            11.0            14.0
------------------------------------------------------------------------------------------------------------------------------------
Total                                                         100.0           100.0           100.0           100.0           100.0
====================================================================================================================================
* 1999 data includes the true-up of the unbilled revenue estimates.
</TABLE>


                                                              II-179


<PAGE>
                      SAVANNAH ELECTRIC AND POWER COMPANY
                               FINANCIAL SECTION


                                  II-180
<PAGE>



MANAGEMENT'S REPORT
Savannah Electric and Power Company 2001 Annual Report


The management of Savannah Electric and Power Company has prepared--and is
responsible for--the financial statements and related information included in
this report. These statements were prepared in accordance with accounting
principles generally accepted in the United States and necessarily include
amounts that are based on the best estimates and judgments of management.
Financial information throughout this annual report is consistent with the
financial statements.

     The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.

     The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.

     The audit committee of the board of directors, composed of five independent
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. Periodically, this committee meets
with management, the internal auditors and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls and financial reporting matters. The internal
auditors and the independent public accountants have access to the members of
the audit committee at any time.

     Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.

     In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Savannah Electric and Power Company in conformity with accounting principles
generally accepted in the United States.


/s/Anthony R. James
Anthony R. James
President
and Chief Executive Officer


/s/K.R. Willis
K. R. Willis
Vice President,
Treasurer, Chief Financial Officer
and Assistant Secretary

February 13, 2002


                                      II-181
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Savannah Electric and Power Company:


We have audited the accompanying balance sheets and statements of capitalization
of Savannah Electric and Power Company (a Georgia corporation and a wholly owned
subsidiary of Southern Company) as of December 31, 2001 and 2000, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.  We believe that our audits provide a reasonable basis
for our opinion.

     In our opinion, the financial statements (pages II-192 through II-206)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 2001 and
2000, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States.

    As explained in Note 1 to the financial statements, effective January 1,
2001, Savannah Electric and Power Company changed its method of accounting for
derivative instruments and hedging activities.




/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002




                                      II-182
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Savannah Electric and Power Company 2001 Annual Report


RESULTS OF OPERATIONS
---------------------

Earnings

Savannah Electric and Power Company's net income for 2001 totaled $22.1 million,
representing a decrease of $0.9 million or 3.9 percent from the prior year.
Earnings were down primarily due to lower retail revenues.

     In 2000, earnings were $23.0 million, representing no significant change
from the prior year.

Revenues

Total operating revenues for 2001 were $283.9 million, reflecting a 4.0 percent
decrease when compared to 2000. The following table summarizes the factors
affecting operating revenues for the past two years:

                                                  Increase (Decrease)
                                    Amount          From Prior Year
                               --------------------------------------
                                     2001           2001       2000
                               --------------------------------------
                                          (in thousands)
    Retail --
       Base Revenues              $159,839    $  (1,968)     $9,272
       Fuel cost recovery
         and other                 109,333       (11,482)    31,085
    -----------------------------------------------------------------
    Total retail                   269,172       (13,450)    40,357
    -----------------------------------------------------------------
    Sales for resale --
       Non-affiliates                8,884         4,136      1,353
       Affiliates                    3,205        (1,769)       823
    -----------------------------------------------------------------
    Total sales for resale          12,089         2,367      2,176
    -----------------------------------------------------------------
    Other operating revenues         2,591          (783)     1,591
    -----------------------------------------------------------------
    Total operating revenues      $283,852      $(11,866)   $44,124
    =================================================================
    Percent change                                  (4.0)%     17.5%
    -----------------------------------------------------------------

     Retail revenues decreased 4.8 percent or $13.5 million in 2001 as compared
to 2000. The primary contributors to the decrease were the negative impact of
mild weather on energy sales and a decrease in fuel revenues, partially due to a
lower average cost of fuel consumed.

     Electric rates include provisions to adjust billings for fluctuations in
fuel costs, the energy component of purchased power costs, and certain other
costs. Under these fuel recovery provisions, fuel revenues generally equal fuel
expenses--including the fuel component of purchased energy--and do not affect
net income.  However, cash flow is affected by the economic loss from
untimely recovery of these receivables. In May 2001, the Company implemented a
Fuel Cost Recovery (FCR) rate increase under a Georgia Public Service Commission
(GPSC) rate order. The order established a new fuel rate to better reflect
current fuel costs and to collect the under-recovered balance. The GPSC-approved
FCR anticipated a three year recovery of the under-recovered fuel balance. Due
to the current year decreases in fuel costs, the Company recovered approximately
70 percent of this balance by year-end 2001.

     Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. These transactions do not
have a significant impact on earnings.

     Sales to affiliated companies within the Southern electric system vary from
year to year depending on demand and the availability and cost of generating
resources at each company. These energy sales do not have a significant impact
on earnings.

Energy Sales

Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour (KWH) sales for 2001 and the percent change by year were as
follows:
                           KWH            Percent Change
                       -------------    -------------------
                           2001           2001      2000
                       -------------    -------------------
                        (in millions)
Residential                   1,659       (0.7)%     5.8%
Commercial                    1,388        1.4       6.3
Industrial                      788       (1.6)     12.2
Other                           134       (1.4)      2.5
                       -------------
Total retail                  3,969       (0.2)      7.1
Sales for resale --
  Non-affiliates                111       43.4      50.3
  Affiliates                     88       (1.0)     15.1
                       -------------
Total                         4,168        0.6%      7.8%
===========================================================

     Total retail energy sales in 2001 decreased slightly from the prior year.
Residential sales decreased reflecting mild weather, somewhat offset by
continued growth in customers. Industrial sales decreased reflecting a slowing
of the economy. Commercial energy sales increased 1.4 percent reflecting
continued customer growth.

                                      II-183


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


     In 2000, total retail energy sales were up by 7.1 percent from the prior
year, reflecting increased energy sales of 12.2 percent to industrial customers
due to the re-opening of an industrial facility under new ownership. Residential
and commercial energy sales also increased reflecting weather related demand and
customer growth.

Expenses

Total operating expenses for 2001 were $234.3 million, a decrease of $9.0
million from the prior year due primarily to decreases in fuel expense and
purchased power from both affiliates and non-affiliates. The decrease in fuel
expense is attributable to a decrease in generation and lower fuel costs.
Purchased power decreased due principally to lower energy costs. Other operation
expense was lower reflecting decreased costs associated with discontinuation of
a marketing program and lower administrative and general expenses. Maintenance
expense increased from 2000 reflecting higher power delivery costs to support
improved customer reliability.

     In 2000, total operating expenses were $243.3 million, an increase of $41.8
million from the prior year. This increase was due primarily to increases in
purchased power from both affiliates and non-affiliates and fuel expense.
Purchased power increased due principally to higher energy costs. Other
operation expense was higher reflecting increased benefit expenses. Maintenance
expense increased from 1999 reflecting higher power delivery and power
generation maintenance costs to support improved customer reliability and unit
availability, respectively. Depreciation and amortization increased reflecting
additional depreciation charges related to the GPSC accounting order. See Note 3
to the financial statements for additional information on the GPSC's 1998
accounting order.

     Fuel and purchased power costs constitute the single largest expense for
the Company. The mix of energy supply is determined primarily by system load,
the unit cost of fuel consumed, and the availability of units.

     The amount and sources of energy supply and the total average cost of
energy supply were as follows:

                                          2001     2000     1999
                                       --------------------------
Total energy supply
   (millions of KWHs)                    4,310    4,286    4,039
Sources of energy supply
   (percent) --
     Coal                                   50       52       45
     Oil                                     1        2        2
     Gas                                     3        5       10
     Purchased Power                        46       41       43
Total average cost of
   energy supply (cents)                  2.87     3.09     2.44
-----------------------------------------------------------------

Effects of Inflation

The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in utility plant with long economic lives. Conventional
accounting for historical cost does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations such as long-term debt and trust preferred securities.
Any recognition of inflation by regulatory authorities is reflected in the rate
of return allowed.

Future Earnings Potential

General

The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from energy sales growth to a less regulated, more
competitive environment.

     Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. These factors include weather,
competition, new short and long-term contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the Company's service area.

                                      II-184


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


     The Company currently operates as a vertically integrated utility providing
electricity to customers within the traditional service area of southeastern
Georgia. Prices for electricity provided by the Company to retail customers are
set by the GPSC. Prices for electricity relating to jointly owned generating
facilities, interconnecting transmission lines, and the exchange of electric
power are set by the Federal Energy Regulatory Commission (FERC).

     As part of the Company's retail rate settlement in 1992, it was informally
agreed that the Company's earned rate of return on common equity should be 12.95
percent. In 1998, the GPSC issued a four-year accounting order settling its
review of the Company's earnings. See Note 3 to the financial statements for
additional information.

     Southern Power Company, a new Southern Company affiliate formed in 2001 to
construct, own, and manage wholesale generating assets in the Southeast, is
currently constructing two 566 megawatt combined cycle units at Plant Wansley to
begin operation in 2002. The GPSC has certified the Company's purchase of 200
megawatts of capacity from these units to serve its retail customers for
approximately seven years.

     The Company filed a base rate case on November 30, 2001 for the first time
since 1985. The primary reason for this base rate case is to recover significant
new costs related to the Plant Wansley power purchase agreement beginning June
2002, as well as other operation and maintenance expense changes. The requested
increase is 7.6 percent of total rates (base plus fuel). In the filing, the
Company announced it would file for a fuel decrease in early 2002 to offset
most, if not all, of the base rate increase.

     The Company is involved in various matters being litigated. See Note 3 to
the financial statements for information regarding material issues that could
possibly affect future earnings.

     Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed under
"Environmental Matters."

Industry Restructuring

The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
the Company's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
industrial and commercial customers and sell energy generation to other
utilities. Also, electricity sales for resale rates are affected by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.

     Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. Some
states have approved initiatives that result in a separation of the ownership
and/or operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While the GPSC has held workshops to
discuss retail competition and industry restructuring, there has been no
proposed or enacted legislation to date in Georgia. Enactment would require
numerous issues to be resolved, including significant ones relating to recovery
of any stranded investments, full cost recovery of energy produced, and other
issues related to the energy crisis that occurred in California. As a result of
that crisis, many states have either discontinued or delayed implementation of
initiatives involving retail deregulation. The Company does compete with other
electric suppliers within the state. In Georgia, most new retail customers with
at least 900 kilowatts of connected load may choose their electricity supplier.

     In December 1999, the FERC issued its final rule on Regional Transmission
Organizations (RTOs). The order encouraged utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company and its operating companies,
including the Company, have submitted a series of status reports informing the


                                     II-185
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing a for-profit RTO known
as SeTrans with a number of non-jurisdictional cooperative and public power
entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans
development process. In January 2002, the sponsors of SeTrans held a public
meeting to form a Stakeholder Advisory Committee, which will participate in the
development of the RTO. Southern Company continues to work with the other
sponsors to develop the SeTrans RTO. The creation of SeTrans is not expected to
have a material impact on Southern Company's financial statements. The outcome
of this matter cannot now be determined.

Accounting Policies

Critical Policy

The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. The Company is subject to the provisions of Financial
Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects
of Certain Types of Regulation. In the event that a portion of the Company's
operations is no longer subject to these provisions, the Company would be
required to write off related regulatory assets and liabilities that are not
specifically recoverable and determine if any other assets have been impaired.
See Note 1 to the financial statements under "Regulatory Assets and Liabilities"
for additional information.

New Accounting Standards

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. Statement No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities. This statement requires that certain derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at fair value, and that changes in the fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. See
Note 1 to the financial statements under "Financial Instruments" for additional
information. The impact on net income in 2001 was not material. An additional
interpretation of Statement No. 133 will result in a change -- effective April
1, 2002 -- in accounting for certain contracts related to fuel supplies that
contain quantity options. These contracts will be accounted for as derivatives
and marked to market. However, due to the existence of the Company's cost-based
fuel recovery clause, this change is not expected to have a material impact on
net income.

     On June 1, 2001, the Company implemented a natural gas/oil hedging program
which was ordered by the GPSC as part of the fuel cost recovery increase filing.
The maximum annual dollar amount of the hedges recoverable through the fuel cost
recovery clause is 10 percent of the annual gas/oil budget or $1.5 million for
2001 and $2.4 million for 2002.

     In June 2001, the FASB issued Statement No. 142, Goodwill and Other
Intangible Assets, which establishes new accounting and reporting standards for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17. Statement No. 142 addresses how intangible
assets that are acquired individually or with a group of other assets -- but not
those acquired in a business combination -- should be accounted for upon
acquisition and on an ongoing basis. Goodwill and intangible assets that have
indefinite useful lives will not be amortized but rather will be tested at least
annually for impairment. Intangible assets that have finite useful lives will
continue to be amortized over their useful lives, which are no longer limited to
40 years. The Company adopted Statement No. 142 in January 2002 with no material
impact on the financial statements.

     Also in June 2001, the FASB issued Statement No. 143, Asset Retirement
Obligations, which establishes new accounting and reporting standards for legal
obligations associated with retiring assets, including decommissioning of
nuclear plants. The liability for an asset's future retirement must be recorded
in the period in which the liability is incurred. The cost must be capitalized
as part of the related long-lived asset and depreciated over the asset's useful
life. Changes in the liability resulting from the passage of time will be
recognized as operating expenses. Statement No. 143 must be adopted by January
1, 2003. The Company has not yet quantified the impact of adopting Statement No.
143 on its financial statements.


                                     II-186
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


FINANCIAL CONDITION
-------------------

Overview

The principal change in the Company's financial condition in 2001 was the
addition of $31.3 million to utility plant. The funds needed for gross property
additions are currently provided from operating activities, principally from
earnings, and non-cash charges to income such as depreciation and deferred
income taxes and from financing activities. See Statements of Cash Flows for
additional information.

Credit Rating Risk

The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.

Exposure to Market Risks

Due to cost-based regulation, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To mitigate residual risks relative to movements in electricity prices, the
Company enters into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market. At December 31, 2001,
exposure from these activities was not material to the Company's financial
statements. Also, if the Company sustained a 100 basis point change in interest
rates for all variable rate long-term debt, the change would affect annualized
interest expense by approximately $0.2 million at December 31, 2001. Fair values
of changes in energy trading contracts and year-end valuations are as follows:

                                                  Changes
                                              During the Year
                                           -------------------
                                               Fair Value
--------------------------------------------------------------
                                               (in thousands)
Contracts beginning of year                        $    36
Contracts realized or settled                          (32)
New contracts at inception                               -
Changes in valuation techniques                          -
Current period changes                              (1,057)
--------------------------------------------------------------
Contracts end of year                              $(1,053)
==============================================================

                                       Source of Year-End
                                        Valuation Prices
                              ---------------------------------
                                                  Maturity
                                 Total     --------------------
                               Fair Value    Year 1   1-3 Years
---------------------------------------------------------------
                                       (in thousands)
---------------------------------------------------------------
Actively quoted                 $(1,053)    $(1,051)      $(2)
External sources                      -           -         -
Models and other
  methods                             -           -         -
---------------------------------------------------------------
Contracts end of Year           $(1,053)    $(1,051)      $(2)
===============================================================

     For additional information, see Note 1 to the financial statements under
"Financial Instruments."

Capital Structure

As of December 31, 2001, the Company's capital structure consisted of 46.8
percent common stockholder's equity, 10.6 percent trust preferred securities,
and 42.6 percent long-term debt, excluding amounts due within one year.

     Maturities and retirements of long-term debt were $50.7 million in 2001,
$0.4 million in 2000, and $16.2 million in 1999.

     In May 2001, the Company issued $20 million of series B 5.12% senior notes
maturing in 2003 and $45 million of series C 6.55% senior notes maturing in
2008. The Company used these proceeds to redeem its $20 million 6 3/8 Series
First Mortgage Bonds due in 2003, to repay long-term bank loans in the amount of
$30 million, and to repay a portion of its short-term indebtedness.

     The composite interest rates and dividend rates for the years 1999 through
2001 as of year-end were as follows:

                                      2001       2000       1999
                                  -------------------------------
Composite interest rates
   on long-term debt                  5.9%       6.6%       6.4%
Trust preferred securities
   dividend rate                      6.9%       6.9%       6.9%
-----------------------------------------------------------------

Capital Requirements for Construction

The Company's projected construction expenditures for the next three years total
$115.7 million ($34.8 million in 2002, $37.6 million in 2003, and $43.3 million
in 2004). Actual construction costs may vary from this estimate because of

                                     II-187


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


factors such as changes in: business conditions; environmental regulations; load
projections; the cost and efficiency of construction labor, equipment and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered. Construction and
upgrading of new and existing transmission and distribution facilities and
upgrading of generating plants will be continuing.

Other Capital Requirements

In addition to the funds needed for the construction program, approximately
$22.5 million will be needed by the end of 2004 for maturities of long-term debt
and present sinking fund requirements.

    Capital requirements, lease obligations, and purchase commitments -
discussed in Notes 4 and 6 to the financial statements -- are as follows:

                                 2002         2003       2004
 ------------------------------------------------------------
                                       (in thousands)
Notes                          $    -      $20,000     $    -
Bonds -
    First mortgage                436           -           -
    Pollution control               -           -           -
Leases -
    Capital                       742         688         627
    Operating                     429         429         429
Purchase commitments
    Fuel                       34,000         300         300
    Purchased power             9,944      13,640      13,656
-------------------------------------------------------------

     Credit arrangements at the beginning of 2002, are as follows:

                                   Expires
                         ---------------------------------
 Total                   2002              2003
 ---------------------------------------------------------
                         (in thousands)
 $65,500              $45,500           $20,000
----------------------------------------------------------

     For additional information, see Note 6 to the financial statements under
"Bank Credit Arrangements".

Environmental Matters

On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The EPA concurrently issued to Southern Company's operating
companies a notice of violation related to 10 generating facilities, which
includes the five facilities mentioned previously and the Company's Plant Kraft.
In early 2000, the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation, and to add Gulf Power,
Mississippi Power, and the Company as defendants. The complaint and notice of
violation are similar to those brought against and issued to several other
electric utilities. These complaints and notices of violation allege that the
utilities had failed to secure necessary permits or install additional pollution
control equipment when performing maintenance and construction at coal burning
plants constructed or under construction prior to 1978. The U.S. District Court
in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in
Georgia and granted the system service company's motion to dismiss on the
grounds that it neither owned nor operated the generating units involved in the
proceedings. The court granted the EPA's motion to add the Company as a
defendant, but it denied the motion to add Gulf Power and Mississippi Power
based on lack of jurisdiction over those companies. The court directed the EPA
to re-file its amended complaint limiting claims to those brought against
Georgia Power and the Company. The EPA re-filed those claims as directed by the
court. Also, the EPA re-filed its claims against Alabama Power in U.S. District
Court in Alabama. It has not re-filed against Gulf Power, Mississippi Power, or
the system service company. The Alabama Power, Georgia Power, and the Company's
cases have been stayed since the spring of 2001, pending a ruling by the U.S.
Court of Appeals for the Eleventh Circuit in the appeal of a very similar New
Source Review enforcement action against the Tennessee Valley Authority (TVA).
The TVA case involves many of the same legal issues raised by the actions
against Alabama Power, Georgia Power, and the Company. Because the outcome of

                                     II-188
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


the TVA case could have a significant adverse impact on Alabama Power and
Georgia Power, both companies are parties to that case as well. The U.S.
District Court in Alabama has indicated that it will revisit the issue of a
continued stay in April 2002. The U.S. District Court in Georgia is currently
considering a motion by the EPA to reopen the Georgia case. Georgia Power and
the Company have opposed that motion.

     The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit. Prior to January 30, 1997, the penalty was
$25,000 per day. An adverse outcome of this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows, and possibly financial condition if such costs are not
recovered through regulated rates.

     In November 1990, the Clean Air Act Amendments of 1990 (Clean Air Act) were
signed into law. Title IV of the Clean Air Act--the acid rain compliance
provision of the law--significantly affected the Company and other subsidiaries
of Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants were required in two phases. Phase
I compliance began in 1995. Southern Company's subsidiaries, including the
Company, achieved Phase I compliance at the affected plants by primarily
switching to low-sulfur coal and with some equipment upgrades. The construction
expenditures for Phase I compliance totaled approximately $2 million for the
Company.

    Phase II sulfur dioxide compliance was required in 2000. Southern Company
used emission allowances and fuel switching to comply with Phase II
requirements. Phase II compliance had no significant impact on the Company.

     A significant portion of costs related to the acid rain and ozone
non-attainment provisions of the Clean Air Act is expected to be recovered
through existing ratemaking provisions. However, there can be no assurance that
all Clean Air Act costs will be recovered.

     In July 1997, the EPA revised the national ambient air quality standards
for ozone and particulate matter. This revision made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA. In addition, the Federal District of
Columbia Circuit Court of Appeals is considering other legal challenges to these
standards. If the standards are eventually upheld, implementation could be
required by 2007 to 2010.

     In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rule affects 21 states, including
Georgia. Compliance is required by May 31, 2004 for most states. For Georgia,
further rulemaking was required, and proposed compliance was delayed until May
1, 2005.

     In December 2000, having completed its utility studies for mercury and
other hazardous air pollutants (HAPS), the EPA issued a determination that an
emission control program for mercury and, perhaps, other HAPS is warranted. The
program is being developed under the Maximum Achievable Control Technology
provisions of the Clean Air Act, and the regulations are scheduled to be
finalized by the end of 2004 with implementation to take place around 2007. In
January 2001, the EPA proposed guidance for the determination of Best Available
Retrofit Technology (BART) emission controls under the Regional Haze
Regulations. Installation of BART controls is expected to take place around
2010. Litigation of the Regional Haze Regulations, including the BART
provisions, is ongoing in the Federal District of Columbia Circuit Court of
Appeals. A court decision is expected in mid-2002.

     Implementation of the final state rules for these initiatives could require
substantial further reductions in nitrogen oxide and sulfur dioxide and
reductions in mercury and other HAPS emissions from fossil-fired generating
facilities and other industries in these states. Additional compliance costs and
capital expenditures resulting from the implementation of these rules and
standards cannot be determined until the results of legal challenges are known,
and the states have adopted their final rules.


                                     II-189
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


     In October 1997, the EPA issued regulations setting forth requirements for
Compliance Assurance Monitoring (CAM) in its state and federal operating permit
programs. These regulations were amended by the EPA in March 2001 in response to
a court order resolving challenges to the rules brought by environmental groups
and industry. Generally, this rule affects the operation and maintenance of
electrostatic precipitators and could involve significant additional ongoing
expense.

     The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; and hazardous waste disposal requirements. The impact of
any new standards will depend on the development and implementation of
applicable regulations.

     The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup and
will recognize in the financial statements costs to clean up known sites.

     Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.

     Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation--if
any--will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.

Sources of Capital

At December 31, 2001, the Company had $65.5 million of short-term and
revolving credit arrangements with banks to meet its short-term cash needs and
to provide additional interim funding for the Company's construction program.
Revolving credit arrangements total $20 million, of which $10 million expires
April 30, 2003 and $10 million expires December 31, 2003.

     The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $32.2 million of commercial
paper.

     The Company's committed credit arrangements provide liquidity support to
the Company's variable rate obligations and to its commercial paper program. The
amount of variable rate obligations outstanding at December 31, 2001 was $22.6
million.

     It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from sources similar to those used in the past. These sources were primarily
from the issuances of first mortgage bonds, other long-term debt, and preferred
stock, in addition to pollution control revenue bonds issued for the Company's
benefit by public authorities, to meet long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company is required to meet certain
earnings coverage requirements specified in its mortgage indenture and corporate
charter to issue new first mortgage bonds and preferred stock. The Company's
coverage ratios are sufficiently high to permit, at present interest rate
levels, any foreseeable security sales. There are no restrictions on the amount
of unsecured indebtedness allowed. The amount of securities which the Company
will be permitted to issue in the future will depend upon market conditions and
other factors prevailing at that time.


                                      II-190


<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2001 Annual Report


Cautionary Statement Regarding Forward-Looking
Information

This Annual Report includes forward-looking statements in addition to historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
"anticipates," "believes," "estimates," "predicts," "projects," "potential" or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
action against the Company; the effects, extent, and timing of the entry of
additional competition in the markets of the Company; the impact of fluctuations
in commodity prices, interest rates, and customer demand; state and federal rate
regulations; political, legal, and economic conditions and developments in the
United States; internal restructuring or other restructuring options that may be
pursued; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or beneficial;
the effects of, and changes in, economic conditions in the United States; the
direct or indirect effects on the Company's business resulting from the
terrorist incidents on September 11, 2001, or any similar such incidents or
responses to such incidents; financial market conditions and the results of
financing efforts; the ability of the Company to obtain additional generating
capacity at competitive prices; weather and other natural phenomena; and other
factors discussed elsewhere herein and in other reports (including the Form
10-K) filed from time to time by the Company with the Securities and Exchange
Commission.



                                     II-191


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
Savannah Electric and Power Company 2001 Annual Report


---------------------------------------------------------------------------------------------------------------------
                                                                       2001                 2000                1999
---------------------------------------------------------------------------------------------------------------------
                                                                                 (in thousands)
Operating Revenues:
<S>                                                                <C>                  <C>                 <C>
Retail sales                                                       $269,172             $282,622            $242,265
Sales for resale --
  Non-affiliates                                                      8,884                4,748               3,395
  Affiliates                                                          3,205                4,974               4,151
Other revenues                                                        2,591                3,374               1,783
---------------------------------------------------------------------------------------------------------------------
Total operating revenues                                            283,852              295,718             251,594
---------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
  Fuel                                                               50,796               57,177              50,530
  Purchased power --
    Non-affiliates                                                   23,147               25,229              14,398
    Affiliates                                                       49,939               50,111              33,398
  Other                                                              50,607               53,086              50,341
Maintenance                                                          19,886               19,334              16,333
Depreciation and amortization (Note 3)                               25,951               25,240              23,841
Taxes other than income taxes                                        13,984               13,116              12,690
---------------------------------------------------------------------------------------------------------------------
Total operating expenses                                            234,310              243,293             201,531
---------------------------------------------------------------------------------------------------------------------
Operating Income                                                     49,542               52,425              50,063
Other Income (Expense):
Interest income                                                         173                  252                 169
Other, net                                                             (686)                (657)               (663)
---------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes                            49,029               52,020              49,569
---------------------------------------------------------------------------------------------------------------------
Interest and Other:
Interest expense, net                                                12,517               12,737              11,938
Distributions on preferred securities of subsidiary                   2,740                2,740               2,740
---------------------------------------------------------------------------------------------------------------------
Total interest and other, net                                        15,257               15,477              14,678
---------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes                                         33,772               36,543              34,891
Income taxes (Note 5)                                                11,731               13,574              11,808
---------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of                                 22,041               22,969              23,083
   Accounting Change
Cumulative effect of accounting change--
  less income taxes of $14 thousand                                      22                    -                   -
---------------------------------------------------------------------------------------------------------------------
Net Income                                                         $ 22,063             $ 22,969            $ 23,083
=====================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>






                                                              II-192


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
Savannah Electric and Power Company 2001 Annual Report

---------------------------------------------------------------------------------------------------------------------------
                                                                             2001                 2000                1999
---------------------------------------------------------------------------------------------------------------------------
                                                                                       (in thousands)
Operating Activities:
<S>                                                                       <C>                  <C>                 <C>
Net income                                                                $22,063              $22,969             $23,083
Adjustments to reconcile net income
 to net cash provided from operating activities --
     Depreciation and amortization                                         27,895               26,639              25,454
     Deferred income taxes and investment tax credits, net                (20,528)                 728              (3,353)
     Other, net                                                             4,084                3,835                 (47)
     Changes in certain current assets and liabilities --
       Receivables, net                                                    24,079              (23,260)             (5,999)
       Fossil fuel stock                                                   (2,711)                 (31)             (2,125)
       Materials and supplies                                              (4,025)                (542)             (1,906)
       Accounts payable                                                    (8,439)               8,881               1,133
       Other                                                               12,631               (4,674)              1,731
---------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities                                55,049               34,545              37,971
---------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions                                                  (31,296)             (27,290)            (29,833)
Other                                                                      (1,875)              (1,835)             (1,715)
---------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities                                    (33,171)             (29,125)            (31,548)
---------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net                                 (13,241)              11,100              34,300
Proceeds --
     Other long-term debt                                                  65,000                    -                   -
     Capital contributions from parent company                               1,561                1,478               1,099
Retirements --
     First mortgage bonds                                                 (20,642)                   -             (15,800)
     Other long-term debt                                                 (30,071)                (251)               (481)
Payment of common stock dividends                                         (21,700)             (24,300)            (25,200)
Other                                                                        (394)                   -                 250
---------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities                                    (19,487)             (11,973)             (5,832)
---------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents                                     2,391               (6,553)                591
Cash and Cash Equivalents at Beginning of Period                                -                6,553               5,962
---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                                $ 2,391                 $  -             $ 6,553
===========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
     Interest (net of amount capitalized)                                 $15,340              $13,329             $14,212
     Income taxes (net of refunds)                                        $21,034              $19,939             $12,647
---------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.

</TABLE>








                                                               II-193


<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Savannah Electric and Power Company 2001 Annual Report

-----------------------------------------------------------------------------------------------------------------------
Assets                                                                                2001                     2000
-----------------------------------------------------------------------------------------------------------------------
                                                                                             (in thousands)
Current Assets:
<S>                                                                               <C>                      <C>
Cash and cash equivalents                                                         $  2,391                 $      -
Receivables --
  Customer accounts receivable                                                      29,959                   28,189
  Under-recovered retail fuel clause revenue                                        11,974                   39,632
  Other accounts and notes receivable                                                2,882                    1,412
  Affiliated companies                                                               1,170                      738
  Accumulated provision for uncollectible accounts                                    (500)                    (407)
Fossil fuel stock, at average cost                                                   9,851                    7,140
Materials and supplies, at average cost                                             12,969                    8,944
Prepaid taxes                                                                       12,511                    8,651
Other                                                                                  586                      377
-----------------------------------------------------------------------------------------------------------------------
Total current assets                                                                83,793                   94,676
-----------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Note 6)                                                                855,290                  829,270
Less accumulated provision for depreciation                                        402,492                  382,030
-----------------------------------------------------------------------------------------------------------------------
                                                                                   452,798                  447,240
Construction work in progress                                                        8,540                    6,782
-----------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment                                               461,338                  454,022
-----------------------------------------------------------------------------------------------------------------------
Other Property and Investments                                                       2,742                    2,066
-----------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 5)                                   12,283                   12,404
Cash surrender value of life insurance for deferred compensation plans              20,002                   17,954
Debt expense, being amortized                                                        3,197                    3,003
Premium on reacquired debt, being amortized                                          6,890                    7,575
Other                                                                                4,498                    2,527
-----------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets                                             46,870                   43,463
-----------------------------------------------------------------------------------------------------------------------
Total Assets                                                                      $594,743                 $594,227
=======================================================================================================================
The accompanying notes are an integral part of these balance sheets.

</TABLE>


                                                              II-194


<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
At December 31, 2001 and 2000
Savannah Electric and Power Company 2001 Annual Report

--------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity                                               2001                     2000
--------------------------------------------------------------------------------------------------------------------
                                                                                          (in thousands)
Current Liabilities:
<S>                                                                            <C>                     <C>
Securities due within one year (Note 6)                                        $  1,178                 $ 30,698
Notes payable                                                                    32,159                   45,400
Accounts payable --
  Affiliated                                                                      5,087                   16,153
  Other                                                                          10,160                    7,738
Customer deposits                                                                 6,237                    5,696
Taxes accrued --
  Income taxes                                                                    2,587                    3,450
  Other                                                                           1,668                    1,435
Interest accrued                                                                  4,014                    4,541
Vacation pay accrued                                                              2,361                    2,276
Other                                                                             9,097                    7,973
--------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                        74,548                  125,360
--------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements)                                    160,709                  116,902
--------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 5)                                       77,331                   79,756
Deferred credits related to income taxes (Note 5)                                13,776                   16,038
Accumulated deferred investment tax credits (Note 5)                              9,952                   10,616
Deferred compensation plans                                                       8,550                    7,695
Employee benefits provisions (Note 2)                                            18,936                   13,509
Other                                                                            14,023                    9,357
--------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                    142,568                  136,971
--------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
  securities of subsidiary trusts holding company junior
  subordinated notes (See accompanying statements) (Note 6)                      40,000                   40,000
--------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements)                       176,918                  174,994
--------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity                                     $594,743                 $594,227
====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
</TABLE>




                                                              II-195


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CAPITALIZATION
At December 31, 2001 and 2000
Savannah Electric and Power Company 2001 Annual Report

---------------------------------------------------------------------------------------------------------------------------
                                                                 2001              2000             2001              2000
---------------------------------------------------------------------------------------------------------------------------
                                                                      (in thousands)                (percent of total)
Long-Term Debt (Note 6):
First mortgage bonds --
       Maturity                           Interest Rates
       --------                           --------------
       <S>                                <C>               <C>                <C>               <C>               <C>
       July 1, 2003                       6.375%             $      -          $ 20,000
       May 1, 2006                        6.90%                20,000            20,000
       July 1, 2023                       7.40%                23,558            24,200
---------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds                                     43,558            64,200
---------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
       6.88% due June 1, 2001                                       -            10,000
       5.12% due May 15, 2003                                  20,000                 -
       6.55% due May 15, 2008                                  45,000                 -
       6.625% due March 17, 2015                               30,000            30,000
       Adjustable rates (6.71% to 6.86% at 1/1/01)
        due 2001                                                    -            20,000
---------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable                                  95,000            60,000
---------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
      Pollution control revenue bonds --
        Non-collateralized:
         Variable rates (1.90% at 1/1/02)
          due 2016-2037                                        17,955            17,955
---------------------------------------------------------------------------------------------------------------------------
Total other long-term debt                                     17,955            17,955
---------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations                                   5,374             5,445
---------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
  requirement -- $9.6 million)                                161,887           147,600
Less amount due within one year (Note 6)                        1,178            30,698
---------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year           160,709           116,902            42.6%             35.2%
---------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
  Redeemable Preferred Securities (Note 6):
$25 liquidation value --
  6.85%                                                        40,000            40,000
---------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million)        40,000            40,000             10.6              12.1
---------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (Note 6):
Common stock, par value $5 per share --
  Authorized  - 16,000,000 shares
  Outstanding - 10,844,635 shares in 2001 and 2000
  Par value                                                    54,223            54,223
  Paid-in capital                                              12,826            11,265
Retained earnings                                             109,869           109,506
---------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity                             176,918           174,994             46.8              52.7
---------------------------------------------------------------------------------------------------------------------------
Total Capitalization                                         $377,627          $331,896           100.0%            100.0%
===========================================================================================================================
The accompanying notes are an integral part of these statements.
</TABLE>



                                                              II-196


<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2001, 2000, and 1999
Savannah Electric and Power Company 2001 Annual Report

----------------------------------------------------------------------------------------------------------------------


                                                 Common            Paid-In           Retained
                                                  Stock            Capital           Earnings            Total
----------------------------------------------------------------------------------------------------------------------
                                                                         (in thousands)

<S>                                                  <C>                <C>              <C>                <C>
Balance at January 1, 1999                            $54,223            $ 8,688          $112,954           $175,865
Net income                                                  -                  -            23,083             23,083
Capital contributions from parent company                   -              1,099                 -              1,099
Cash dividends on common stock                              -                  -           (25,200)           (25,200)
----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999                           54,223              9,787           110,837            174,847
Net income                                                  -                  -            22,969             22,969
Capital contributions from parent company                   -              1,478                 -              1,478
Cash dividends on common stock                              -                  -           (24,300)           (24,300)
----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000                           54,223             11,265           109,506            174,994
Net income                                                  -                  -            22,063             22,063
Capital contributions from parent company                   -              1,561                 -              1,561
Cash dividends on common stock                              -                  -           (21,700)           (21,700)
----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 (Note 6)                 $54,223            $12,826          $109,869           $176,918
======================================================================================================================
The accompanying notes are an integral part of these statements.

</TABLE>

                                                              II-197



<PAGE>
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2001 Annual Report


1.  SUMMARY OF SIGNIFICANT ACCOUNTING
    POLICIES

General

Savannah Electric and Power Company (the Company) is a wholly owned subsidiary
of Southern Company, which is the parent company of five operating companies, a
system service company, Southern Communications Services (Southern LINC),
Southern Nuclear Operating Company (Southern Nuclear), Southern Power Company
(Southern Power), and other direct and indirect subsidiaries. The operating
companies provide electric service in four states. Contracts among the operating
companies--related to jointly owned generating facilities, interconnecting
transmission lines, and the exchange of electric power--are regulated by the
Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange
Commission. The system service company provides, at cost, specialized services
to Southern Company and subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Power was
established in 2001 to construct, own, and manage Southern Company's competitive
generation assets and sell electricity at market-based rates in the wholesale
market.

     Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
also is subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows accounting principles generally accepted
in the United States and complies with the accounting policies and practices
prescribed by the GPSC. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the
use of estimates, and the actual results may differ from those estimates.

     Certain prior years' data presented in the financial statements has been
reclassified to conform with the current year presentation.

Affiliate Transactions

The Company has an agreement with the system service company under which the
following services are rendered to the Company at cost: general and design
engineering, purchasing, accounting and statistical, finance and treasury, tax,
information resources, marketing, auditing, insurance and employee benefits,
human resources, systems and procedures, and other administrative services with
respect to business and operations and power pool operations. Costs for these
services amounted to $15.0 million, $15.1 million, and $16.0 million during
2001, 2000, and 1999, respectively.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:

                                         2001            2000
                                     --------------------------
                                         (in thousands)
Deferred income tax charges             $ 12,283      $ 12,404
Premium on reacquired debt                 6,890         7,575
Gas by-pass facility                         209           299
Deferred income tax credits              (13,776)      (16,038)
Storm damage reserves                     (4,228)       (2,733)
Accelerated depreciation                  (8,000)       (5,500)
---------------------------------------------------------------
Total                                   $ (6,622)     $ (3,993)
===============================================================

     In the event that a portion of the Company's operations is no longer
subject to the provisions of FASB Statement No. 71, the Company would be
required to write off related regulatory assets and liabilities that are not
specifically recoverable through regulated rates. In addition, the Company would
be required to determine if any impairment to other assets exists, including
plant, and write down the assets, if impaired, to their fair value.

Revenues and Fuel Costs

The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area of
southeastern Georgia and to wholesale customers in the Southeast.


                                     II-198
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


    Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is
used. Electric rates for the Company include provisions to adjust billings for
fluctuations in fuel costs, the energy component of purchased power costs, and
certain other costs. Revenues are adjusted for differences between recoverable
fuel costs and amounts actually recovered in current regulated rates.

    The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
uncollectible accounts averaged less than 1 percent of revenues.

    In 2001, the GPSC approved an increase in the Company's fuel cost recovery
rate amounting to a total average annual rate increase of 18 percent for all
customer classes. An increase of slightly over one-third of a cent per
kilowatt-hour was approved in 2000.

Depreciation and Amortization

Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.0 percent in 2001,
2000, and 1999. When property subject to depreciation is retired or otherwise
disposed of in the normal course of business, its cost--together with the cost
of removal, less salvage--is charged to the accumulated provision for
depreciation. Minor items of property included in the original cost of the plant
are retired when the related property unit is retired. Depreciation expense
includes an amount for the expected cost of removal of certain facilities. In
2001, 2000, and 1999, the Company recorded accelerated depreciation of $2.5
million, $2.5 million, and $2.0 million, respectively, in accordance with the
GPSC's 1998 rate order. See Note 3 to the financial statements for more
information.

Income Taxes

The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.

Allowance for Funds Used During Construction
    (AFUDC)

AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rates used by the Company to calculate AFUDC
were 5.13 percent in 2001, 6.87 percent in 2000, and 6.26 percent in 1999.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory
disallowances and impairments. Original cost includes: materials; labor; minor
items of property; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits, and AFUDC. The cost of
maintenance, repairs, and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property exclusive of minor
items of property is capitalized.

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.

Materials and Supplies

Generally, materials and supplies include the costs of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.

Financial Instruments

Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. The impact on net
income was immaterial. The Company uses derivative financial instruments to
hedge exposure to fluctuations in certain commodity prices. Gains and losses on
qualifying hedges are deferred and recognized either as income or as an
adjustment to the carrying amount of the hedged item when the transaction
occurs.

                                      II-199


<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


     The Company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The Company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the Company's exposure to counterparty credit risk.

   The five operating companies and Southern Power enter into commodity related
forward and option contracts to limit exposure to changing prices on certain
fuel purchases and electricity purchases and sales. Substantially all of
Southern Company's bulk energy purchases and sales contracts meet the definition
of a derivative under FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities. In many cases, these fuel and electricity
contracts qualify for normal purchase and sale exceptions under Statement No.
133 and are accounted for under the accrual method. Other contracts qualify as
cash flow hedges of anticipated transactions, resulting in the deferral of
related gains and losses, and are recorded in other comprehensive income until
the hedged transactions occur. Any ineffectiveness is recognized currently in
net income. Contracts that do not qualify for the normal purchase and sale
exception and that do not meet the hedge requirements are marked to market
through current period income.

     On June 1, 2001, the Company implemented a natural gas/oil hedging program
which was ordered by the GPSC as part of the fuel cost recovery increase filing.
The maximum annual dollar amount of the hedges recoverable through the fuel cost
recovery clause is 10 percent of the annual gas/oil budget or $1.5 million for
2001 and $2.4 million for 2002.

     The Company's other financial instruments for which the carrying amounts
did not equal fair value at December 31 were as follows:

                                      Carrying           Fair
                                        Amount          Value
                                    --------------------------
                                          (in millions)
Long-term debt:
    At December 31, 2001                 $157             $157
    At December 31, 2000                 $142             $140
Trust preferred securities:
    At December 31, 2001                  $40              $38
    At December 31, 2000                  $40              $36

     The fair values for long-term debt and trust preferred securities were
based on either closing market prices or closing prices of comparable
instruments.

2.  RETIREMENT BENEFITS

The Company has defined benefit, trusteed, non-contributory pension plans that
cover substantially all employees. The Company provides certain medical care and
life insurance benefits for retired employees. The Company funds trusts to the
extent required by the GPSC and the FERC. The measurement date for plan assets
and obligations is September 30 of each year. In late 2000, the Company adopted
several pension and postretirement benefit plan changes that had the effect of
increasing benefits to both current and future retirees.

Pension Plans

Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:

                                            Projected
                                       Benefit Obligations
                                    ---------------------------
                                          2001          2000
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $71,521       $66,509
Service cost                             2,074         1,844
Interest cost                            5,426         4,854
Benefits paid                           (3,986)       (3,469)
Actuarial loss and
    employee transfers                     894         1,564
Amendments                               3,621           219
---------------------------------------------------------------
Balance at end of year                 $79,550       $71,521
===============================================================

                                           Plan Assets
                                    ---------------------------
                                          2001          2000
--------------------------------========================-------
                                          (in thousands)
Balance at beginning of year           $61,880       $54,480
Actual return on plan assets            (8,911)       10,493
Benefits paid                           (3,570)       (3,210)
Employee transfers                       1,459           117
---------------------------------====================----------
Balance at end of year                 $50,858       $61,880
===============================================================


                                      II-200



<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


     The accrued pension costs recognized in the Balance Sheets
were as follows:

                                         2001           2000
---------------------------------------------------------------
                                         (in thousands)
Funded status                        $(28,692)       $(9,641)
Unrecognized transition
  obligation                                -             89
Unrecognized prior service
  cost                                  7,401          4,391
Unrecognized net loss (gain)           12,336           (235)
---------------------------------------------------------------
Accrued liability recognized
  in the Balance Sheets              $ (8,955)       $(5,396)
===============================================================

      Components of the pension plan's net periodic cost were as follows:

                                    2001       2000       1999
-----------------------------------------------------------------
                                          (in thousands)
Service cost                     $ 2,074    $ 1,844    $ 1,838
Interest cost                      5,426      4,854      4,327
Expected return on plan
    assets                        (4,215)    (4,174)    (4,063)
Recognized net loss                   16          -        171
Net amortization                     700        503        478
-----------------------------------------------------------------
Net pension cost                 $ 4,001    $ 3,027    $ 2,751
=================================================================

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:

                                           Accumulated
                                        Benefit Obligations
                                    ---------------------------
                                          2001          2000
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $26,124       $22,904
Service cost                               433           376
Interest cost                            2,022         1,865
Benefits paid                             (987)         (963)
Actuarial gain and
    employee transfers                  (1,214)       (1,367)
Amendments                               1,743         3,309
---------------------------------------------------------------
Balance at end of year                 $28,121       $26,124
===============================================================

                                           Plan Assets
                                    ---------------------------
                                        2001           2000
---------------------------------------------------------------
                                          (in thousands)
Balance at beginning of year           $6,910        $5,254
Actual return on plan assets             (789)          606
Employer contributions                  2,267         2,013
Benefits paid                            (987)         (963)
---------------------------------------------------------------
Balance at end of year                 $7,401        $6,910
===============================================================

    The accrued postretirement costs recognized in the Balance Sheets
were as follows:

                                          2001           2000
---------------------------------------------------------------
                                           (in thousands)
Funded status                          $(20,720)    $(19,214)
Unrecognized transition
    obligation                            5,431        5,925
Unamortized prior service cost            4,691        3,185
Unrecognized net loss                     1,831        1,701
Fourth quarter contributions              1,577        1,493
---------------------------------------------------------------
Accrued liability recognized in
    the Balance Sheets                 $ (7,190)    $ (6,910)
===============================================================

    Components of the postretirement plan's net periodic cost were as follows:

                                        2001     2000      1999
----------------------------------------------------------------
                                            (in thousands)
Service cost                          $  433   $  376    $  404
Interest cost                          2,022    1,865     1,549
Expected return on plan assets          (555)    (429)     (345)
Recognized net loss                        -       66       152
Net amortization                         731      618       494
----------------------------------------------------------------
Net postretirement cost               $2,631   $2,496    $2,254
================================================================

    The weighted average rates assumed in the actuarial calculations for both
the pension plan and postretirement benefits plan were:

                                          2001         2000
-------------------------------------------------------------
Discount                                  7.50%        7.50%
Annual salary increase                    5.00         5.00
Long-term return on plan assets           8.50         8.50
-------------------------------------------------------------

      An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2001, decreasing gradually to 5.25 percent through the year 2010,
and remaining at that level thereafter. An annual increase or decrease in the


                                     II-201
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
2001 as follows:

                                     1 Percent     1 Percent
                                      Increase      Decrease
---------------------------------------------------------------
                                          (in thousands)
Benefit obligation                     $2,070        $2,051
Service and interest costs                181           179
===============================================================

     The Company has a supplemental retirement plan for certain executive
employees. The plan is unfunded and payable from the general funds of the
Company. The Company has purchased life insurance on participating executives
and plans to use these policies to satisfy this obligation.

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2001, 2000, and 1999 were $1.0
million, $0.9 million, and $0.9 million, respectively.

3.   CONTINGENCIES AND REGULATORY
     MATTERS

General

The Company is subject to certain claims and legal actions arising in the
ordinary course of business. In the opinion of management, after consultation
with legal counsel, the ultimate disposition of these matters is not expected to
have a material adverse effect on the Company's financial condition.

Environmental Litigation

On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The Clean Air Act authorizes civil penalties of up to $27,500
per day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.

   The EPA concurrently issued to the operating companies a notice of violation
related to 10 generating facilities, which includes the five facilities
mentioned previously and the Company's Plant Kraft. In early 2000, the EPA filed
a motion to amend its complaint to add the violations alleged in its notice of
violation, and to add Gulf Power, Mississippi Power, and the Company as
defendants. The complaint and notice of violation are similar to those brought
against and issued to several other electric utilities. These complaints and
notices of violation allege that the utilities had failed to secure necessary
permits or install additional pollution control equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. The U.S. District Court in Georgia granted Alabama
Power's motion to dismiss for lack of jurisdiction in Georgia and granted the
system service company's motion to dismiss on the grounds that it neither owned
nor operated the generating units involved in the proceedings. The court granted
the EPA's motion to add the Company as a defendant, but it denied the motion to
add Gulf Power and Mississippi Power based on lack of jurisdiction over those
companies. The court directed the EPA to re-file its amended complaint limiting
claims to those brought against Georgia Power and the Company. The EPA re-filed
those claims as directed by the court. Also, the EPA re-filed its claims against
Alabama Power in U.S. District Court in Alabama. It has not re-filed against
Gulf Power, Mississippi Power, or the system service company.

   The Alabama Power, Georgia Power, and the Company's cases have been stayed
since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the
Eleventh Circuit in the appeal of a very similar New Source Review enforcement
action against the Tennessee Valley Authority (TVA). The TVA case involves many
of the same legal issues raised by the actions against Alabama Power, Georgia
Power, and the Company. Because the outcome of the TVA case could have a


                                      II-202
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


significant adverse impact on Alabama Power and Georgia Power, both companies
are parties to that case as well. The U.S. District Court in Alabama has
indicated that it will revisit the issue of a continued stay in April 2002. The
U.S. District Court in Georgia is currently considering a motion by the EPA to
reopen the Georgia case. Georgia Power and the Company have opposed that motion.

     The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.

Retail Regulatory Matters

Rates to retail customers served by the Company are regulated by the GPSC. As
part of the Company's rate settlement in 1992, it was informally agreed that the
Company's earned rate of return on common equity should be 12.95 percent.

     In 1998, the GPSC approved a four-year accounting order for the Company.
Under this order, the Company will reduce the electric rates of its small
business customers by approximately $11 million over four years. The Company
will also expense an additional $1.95 million in storm damage accruals and
accrue an additional $8 million in depreciation on generating assets over the
term of the order. The additional depreciation will be accumulated in a
regulatory liability account to be available to mitigate any potential stranded
costs. In addition, the Company has discretionary authority to provide up to an
additional $0.3 million per year in storm damage accruals and up to an
additional $4.0 million in depreciation expense over the four years. Total storm
damages accrued under the order were $1.5 million per year in 2001, 2000, and
1999 which included discretionary expense of $0.3 million in each year. No
discretionary depreciation was recorded in the last three years. Over the term
of the order, the Company is precluded from asking for a rate increase except
upon significant changes in economic conditions, new laws, or regulations. There
is a quarterly monitoring of the Company's earnings performance.

     The Company filed a base rate case November 30, 2001 for the first time
since 1985. The primary reason for this base rate case is to recover significant
new costs related to the 200 megawatt Plant Wansley power purchase agreement
beginning June 2002, as well as other operation and maintenance expense changes.
The requested increase is 7.6 percent of total rates (base plus fuel). In the
filing, the Company announced it would file in early 2002 for a fuel decrease
which would offset most, if not all, of the base rate increase.

4.   COMMITMENTS

Construction Program

The Company is engaged in a continuous construction program, currently estimated
to total $34.8 million in 2002, $37.6 million in 2003, and $43.3 million in
2004. The construction program is subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include: changes in business conditions; revised load
growth estimates; changes in environmental regulations; increasing costs of
labor, equipment, and materials; and changes in cost of capital. The Company
does not have any traditional baseload generating plants under construction.
However, construction related to new and upgrading of existing transmission and
distribution facilities and the upgrading of generating plants will continue.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. The Company has fuel
commitments of $34 million for 2002, $0.3 million for each of the four years
2003 through 2006, and $6 million for 2007 and beyond.

     In addition, the system service company acts as agent for the Company and
the other operating companies and Southern Power with regard to natural gas
purchases. Natural gas purchases (in dollars) are based on various indices at
the actual time of delivery; therefore, only the volume commitments are firm.
The Company's committed volumes allocated based on usage projections as of


                                     II-203
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


December 31, 2001 are as follows:

Year                                              Natural Gas
----                                            -------------
                                                     (MMBtu)
2002                                                4,765,152
2003                                                4,356,394
2004                                                3,049,457
2005                                                2,115,548
2006                                                1,804,674
2007 and beyond                                       612,901
---------------------------------------------------------------
Total commitments                                  16,704,126
===============================================================

     The Company has entered into various long-term commitments for the purchase
of electricity, substantially all from affiliated companies, including the Plant
Wansley purchased power agreement. Estimated total long-term obligations at
December 31, 2001 were as follows:

Year                                             Commitments
----                                           --------------
                                               (in thousands)
2002                                              $  9,944
2003                                                13,640
2004                                                13,656
2005                                                13,670
2006                                                13,686
2007 and beyond                                     41,152
---------------------------------------------------------------
Total commitments                                 $105,748
===============================================================

Operating Leases

The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $0.4 million for 2001, $0.4 million for 2000, and $0.5
million for 1999.

     At December 31, 2001, estimated future minimum lease payments for
noncancelable operating leases were as follows:

                                                 Rental
                                               Commitments
                                              ---------------
                                             (in thousands)
2002                                               $429
2003                                                429
2004                                                429
2005                                                429
2006                                                429
2007 and thereafter                               4,894
--------------------------------------------------------------
Total commitments                                $7,039
==============================================================

5.   INCOME TAXES

At December 31, 2001, tax-related regulatory assets and liabilities were $12.3
million and $13.8 million, respectively. The assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized interest. The liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.

     Details of income tax provisions are as follows:

                                        2001     2000      1999
                                       ---------------------------
                                          (in thousands)
Total provision for income taxes
Federal --
   Currently payable                $ 27,991  $11,102   $12,968
   Deferred                          (17,951)      75    (3,329)
------------------------------------------------------------------
                                      10,040   11,177     9,639
------------------------------------------------------------------
State --
   Currently payable                   4,282    1,744     2,193
   Deferred                           (2,577)     653       (24)
------------------------------------------------------------------
                                       1,705    2,397     2,169
------------------------------------------------------------------
Total                               $ 11,745  $13,574   $11,808
==================================================================

   The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:

                                                 2001        2000
                                             ---------------------
                                                 (in thousands)
Deferred tax liabilities:
   Accelerated depreciation                   $81,654     $76,901
   Property basis differences                 (1,437)       5,904
   Other                                        6,566      17,807
------------------------------------------------------------------
Total                                          86,783     100,612
------------------------------------------------------------------
Deferred tax assets:
   Pension and other benefits                  11,403       9,744
   Other                                       10,560       7,662
------------------------------------------------------------------
Total                                          21,963      17,406
------------------------------------------------------------------
Total deferred tax liabilities, net            64,820      83,206
Portion included in current assets
(liabilities), net                             12,511     (3,450)
------------------------------------------------------------------
Accumulated deferred income taxes
   in the Balance Sheets                      $77,331     $79,756
==================================================================

     In accordance with regulatory requirements, deferred investment tax credits
are amortized over the lives of the related property with such amortization
normally applied as a credit to reduce depreciation in the Statements of Income.


                                     II-204
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


Credits amortized in this manner amounted to $0.7 million per year in 2001,
2000, and 1999. At December 31, 2001, all investment tax credits available to
reduce federal income taxes payable had been utilized.

     A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

                                      2001      2000       1999
                                    -----------------------------
 Federal statutory tax rate             35%      35%       35%
 State income tax, net of
    Federal income tax benefit           3        4         4
 Other                                  (3)      (2)       (5)
 ----------------------------------------------------------------
 Effective income tax rate              35%      37%       34%
 ================================================================

     Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.

6.   CAPITALIZATION

Trust Preferred Securities

In December 1998, Savannah Electric Capital Trust I, of which the Company owns
all of the common securities, issued $40 million of 6.85% mandatorily redeemable
preferred securities. Substantially all of the assets of the Trust are $40
million aggregate principal amount of the Company's 6.85% junior subordinated
notes due December 31, 2028.

     The Company considers that the mechanisms and obligations relating to the
trust preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of payment obligations with respect to the preferred
securities of Savannah Electric Capital Trust I.

     Savannah Electric Capital Trust I is a subsidiary of the Company, and
accordingly is consolidated in the Company's financial statements.

Long-Term Debt and Capital Leases

The Company's Indenture related to its First Mortgage Bonds is unlimited as to
the authorized amount of bonds which may be issued, provided that required
property additions, earnings, and other provisions of such Indenture are met.

     Maturities and retirements of long-term debt were $50.7 million in 2001,
$0.4 million in 2000, and $16.2 million in 1999.

     In May 2001, the Company issued $20 million of series B 5.12% senior notes
maturing May 15, 2003 and $45 million of series C 6.55% senior notes maturing
May 15, 2008. The Company used these proceeds to redeem its $20 million 6 3/8
Series First Mortgage Bonds due July 1, 2003, to repay long-term bank loans in
the amount of $30 million, and to repay a portion of its short-term
indebtedness.

     Assets acquired under capital leases are recorded as utility plant in
service, and the related obligation is classified as other long-term debt.
Leases are capitalized at the net present value of the future lease payments.
However, for ratemaking purposes, these obligations are treated as operating
leases, and as such, lease payments are charged to expense as incurred.

Securities Due Within One Year

A summary of the sinking fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:

                                                   2001       2000
                                              ---------------------
                                                  (in thousands)
Bond sinking fund requirement                      $436     $  642
Less:
   Portion to be satisfied by
     certifying property additions                    -        642
-------------------------------------------------------- ----------
Cash sinking fund requirement                       436          -
Other long-term debt maturities                     742     30,698
-------------------------------------------------------------------
Total                                            $1,178    $30,698
===================================================================

     The first mortgage bond improvement (sinking) fund requirements amount to 1
percent of each outstanding series of bonds authenticated under the Indenture
prior to January 1 of each year, other than those issued to collateralize
pollution control and other obligations. The requirements may be satisfied by
depositing cash or reacquiring bonds, or by pledging additional property equal
to 1 2/3 times the requirements.

     The sinking fund requirements of first mortgage bonds were satisfied by
cash redemption in 2001 and by certifying property additions in 2000. It is
anticipated that the 2002 requirement will be satisfied by cash redemption.


                                     II-205
<PAGE>
NOTES (continued)
Savannah Electric and Power Company 2001 Annual Report


Sinking fund requirements and/or maturities through 2006 applicable to long-term
debt are as follows: $1.2 million in 2002; $20.7 million in 2003; $0.6 million
in 2004; $0.6 million in 2005; and $20.6 million in 2006.

Bank Credit Arrangements

At the end of 2001, unused credit arrangements with five banks totaled $65.5
million and expire at various times during 2002 and 2003.

     The Company has revolving credit arrangements of $20 million, of which $10
million expires April 30, 2003 and $10 million expires December 31, 2003. One of
these agreements allows short-term borrowings to be converted into term loans,
payable in 12 equal quarterly installments, with the first installment due at
the end of the first calendar quarter after the applicable termination date or
at an earlier date at the Company's option.

     In connection with these credit arrangements, the Company agrees to pay
commitment fees based on the unused portions of the commitments.

     The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2001, the Company had outstanding $32.2 million of commercial
paper.

     The Company's committed credit arrangements provide liquidity support to
the Company's variable rate obligations and to its commercial paper program. The
amount of variable rate obligations outstanding at December 31, 2001 was $22.6
million.

Assets Subject to Lien

As amended and supplemented, the Company's Indenture of Mortgage, which secures
the first mortgage bonds issued by the Company, constitutes a direct first lien
on substantially all of the Company's fixed property and franchises. A second
lien for $14 million in pollution control obligations is secured by a portion of
the Plant McIntosh property.

Common Stock Dividend Restrictions

The Company's Indenture contains certain limitations on the payment of cash
dividends on common stock. At December 31, 2001, approximately $68 million of
retained earnings was restricted against the payment of cash dividends on common
stock under the terms of the Indenture.

7.    QUARTERLY FINANCIAL INFORMATION
      (UNAUDITED)

Summarized quarterly financial data for 2001 and 2000 are as follows (in
thousands):

                                                Net Income After
                      Operating    Operating      Dividends on
Quarter Ended          Revenues      Income     Preferred Stock
------------------------------------------------------------------

March 2001             $61,691    $  6,799       $  1,476
June 2001               73,970      14,620          6,246
September 2001          93,583      22,332         11,309
December 2001           54,608       5,791          3,032

March 2000             $52,390    $  6,583       $  1,643
June 2000               72,780      14,904          6,287
September 2000          98,849      24,461         12,351
December 2000           71,699       6,477          2,688
---------------------------------------------------------------

     The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.



                                     II-206
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001
Savannah Electric and Power Company 2001 Annual Report


----------------------------------------------------------------------------------------------------------------------------------
                                                             2001            2000            1999            1998            1997
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>             <C>             <C>             <C>             <C>
Operating Revenues (in thousands)                        $283,852        $295,718        $251,594        $254,455        $226,277
Net Income after Dividends
  on Preferred Stock (in thousands)                       $22,063         $22,969         $23,083         $23,644         $23,847
Cash Dividends
  on Common Stock (in thousands)                          $21,700         $24,300         $25,200         $23,500         $20,500
Return on Average Common Equity (percent)                   12.54           13.13           13.16           13.44           13.71
Total Assets (in thousands)                              $594,743        $594,227        $570,218        $555,799        $547,352
Gross Property Additions (in thousands)                   $31,296         $27,290         $29,833         $18,071         $18,846
----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity                                      $176,918        $174,994        $174,847        $175,865        $175,631
Preferred stock                                                 -               -               -               -          35,000
Company obligated mandatorily
  redeemable preferred securities                          40,000          40,000          40,000          40,000               -
Long-term debt                                            160,709         116,902         147,147         163,443         142,846
----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)            $377,627        $331,896        $361,994        $379,308        $353,477
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity                                          46.8            52.7            48.3            46.4            49.7
Preferred stock                                                 -               -               -               -             9.9
Company obligated mandatorily
  redeemable preferred securities                            10.6            12.1            11.0            10.5               -
Long-term debt                                               42.6            35.2            40.7            43.1            40.4
----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year)               100.0           100.0           100.0           100.0           100.0
==================================================================================================================================
Security Ratings:
First Mortgage Bonds -
   Moody's                                                     A1              A1              A1              A1              A1
   Standard and Poor's                                         A+              A+             AA-             AA-             AA-
Preferred Stock -
   Moody's                                                   Baa1              a2              a2              a2              a2
   Standard and Poor's                                       BBB+            BBB+              A-               A               A
Unsecured Long-Term Debt -
   Moody's                                                     A2               -               -               -               -
   Standard and Poor's                                          A               -               -               -               -
==================================================================================================================================
Customers (year-end):
Residential                                               117,199         115,646         112,891         110,437         109,092
Commercial                                                 16,121          15,727          15,433          15,328          14,233
Industrial                                                     76              75              67              63              64
Other                                                         474             444             417             377           1,129
----------------------------------------------------------------------------------------------------------------------------------
Total                                                     133,870         131,892         128,808         126,205         124,518
==================================================================================================================================
Employees (year-end):                                         550             554             533             542             535
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                                              II-207



<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)
Savannah Electric and Power Company 2001 Annual Report


-----------------------------------------------------------------------------------------------------------------------------
                                                        2001            2000            1999            1998            1997
-----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
<S>                                                 <C>             <C>             <C>             <C>              <C>
Residential                                         $123,819        $129,520        $112,371        $109,393         $96,587
Commercial                                           100,835         102,116          88,449          86,231          78,949
Industrial                                            34,971          40,839          32,233          37,865          35,301
Other                                                  9,547          10,147           9,212           8,838           8,621
-----------------------------------------------------------------------------------------------------------------------------
Total retail                                         269,172         282,622         242,265         242,327         219,458
Sales for resale  - non-affiliates                     8,884           4,748           3,395           4,548           3,467
Sales for resale  - affiliates                         3,205           4,974           4,151           3,016           2,052
-----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity             281,261         292,344         249,811         249,891         224,977
Other revenues                                         2,591           3,374           1,783           4,564           1,300
-----------------------------------------------------------------------------------------------------------------------------
Total                                               $283,852        $295,718        $251,594        $254,455        $226,277
=============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential                                        1,658,735       1,671,089       1,579,068       1,539,792       1,428,337
Commercial                                         1,388,357       1,369,448       1,287,832       1,236,337       1,156,078
Industrial                                           787,674         800,150         713,448         900,012         881,261
Other                                                133,967         135,824         132,555         131,142         124,490
-----------------------------------------------------------------------------------------------------------------------------
Total retail                                       3,968,733       3,976,511       3,712,903       3,807,283       3,590,166
Sales for resale  - non-affiliates                   111,145          77,481          51,548          53,294          94,280
Sales for resale  - affiliates                        87,799          88,646          76,988          58,415          54,509
-----------------------------------------------------------------------------------------------------------------------------
Total                                              4,167,677       4,142,638       3,841,439       3,918,992       3,738,955
=============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential                                             7.46            7.75            7.12            7.10            6.76
Commercial                                              7.26            7.46            6.87            6.97            6.83
Industrial                                              4.44            5.10            4.52            4.21            4.01
Total retail                                            6.78            7.11            6.52            6.36            6.11
Sales for resale                                        6.08            5.85            5.87            6.77            3.71
Total sales                                             6.75            7.06            6.50            6.38            6.02
Residential Average Annual
  Kilowatt-Hour Use Per Customer                      14,241          14,593          14,100          14,061          13,231
Residential Average Annual
  Revenue Per Customer                             $1,063.07       $1,131.08       $1,003.39         $998.94         $894.73
Plant Nameplate Capacity
  Ratings (year-end) (megawatts)                         788             788             788             788             788
Maximum Peak-Hour Demand (megawatts):
Winter                                                   758             724             719             582             625
Summer                                                   846             878             875             846             802
Annual Load Factor (percent)                            55.9            53.4            51.2            54.9            54.3
Plant Availability Fossil-Steam (percent):              81.2            78.5            72.8            72.9            93.7
-----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal                                                    50.5            51.6            44.6            41.6            34.4
Oil and gas                                              4.0             6.9            12.3            12.9             5.2
Purchased power -
  From non-affiliates                                    5.3             7.7             5.3             3.4             1.4
  From affiliates                                       40.2            33.8            37.8            42.1            59.0
-----------------------------------------------------------------------------------------------------------------------------
Total                                                  100.0           100.0           100.0           100.0           100.0
=============================================================================================================================
</TABLE>

                                                              II-208



<PAGE>

                                    PART III

Items 10, 11, 12 and 13 for SOUTHERN are incorporated by reference to ELECTION
OF DIRECTORS in SOUTHERN's definitive Proxy Statement relating to the 2002
Annual Meeting of Stockholders.

     Additionally, Items 10, 11, 12 and 13 for ALABAMA, GEORGIA, GULF and
MISSISSIPPI are incorporated by reference to the Information Statements of
ALABAMA, GEORGIA, GULF and MISSISSIPPI relating to each of their respective 2002
Annual Meetings of Shareholders.

     The ages of directors and executive officers in Item 10 set forth below are
as of December 31, 2001.

ITEM 10.        DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Identification of directors of SAVANNAH.

Anthony R. James
President and Chief Executive Officer
Age 51
Served as Director since 5-3-01

Gus H. Bell (1)
Age 64
Served as Director since 7-20-99

Archie H. Davis (1)
Age 60
Served as Director since 2-18-97

Walter D. Gnann (1)
Age 66
Served as Director since 5-17-83

Robert B. Miller, III (1)
Age 56
Served as Director since 5-17-83

Arnold M. Tenenbaum (1)
Age 65
Served as Director since 5-17-77

(1)    No position other than Director.

     Each of the above is currently a director of SAVANNAH, serving a term
running from the last annual meeting of SAVANNAH's stockholder (May 3, 2001) for
one year until the next annual meeting or until a successor is elected and
qualified, except for Mr. James, whose election was effective on the date
indicated.

     There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of SAVANNAH acting solely in their capacities as such.

Identification of executive officers of SAVANNAH.

Anthony R. James
President, Chief Executive Officer and Director
Age 51
Served as Executive Officer since 7-27-00

W. Miles Greer
Vice President - Customer Operations and
External Affairs
Age 58
Served as Executive Officer since 11-20-85

Sandra R. Miller
Vice President - Power Generation
Age 49
Served as Executive Officer since 7-26-01

Kirby R. Willis
Vice President, Treasurer and Chief Financial Officer
Age 50
Served as Executive Officer since 1-1-94

     Each of the above is currently an executive officer of SAVANNAH, serving a
term running from the meeting of the directors held on July 26, 2001 for the
ensuing year.

     There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as an officer, other than any arrangements or understandings with
officers of SAVANNAH acting solely in their capacities as such.

Identification of certain significant employees.
     None.

Family relationships.
     None.

                                     III-1

<PAGE>


Business experience.

Anthony R. James - President and Chief Executive Officer since 2001. He
previously served as Vice President of Power Generation and Senior Production
Officer from 2000 to 2001 and also as Central Cluster Manager at GEORGIA's Plant
Scherer from 2000 to 2001. He served as Plant Manager at GEORGIA's Plant Scherer
from 1996 to 2000. Director of SunTrust Bank of Savannah.

Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell
and DeYoung, Inc., (specializing in environmental, industrial, structural,
architectural and civil engineering), Savannah, Georgia.  Director of SunTrust
Bank of Savannah.

Archie H. Davis - President and Chief Executive Officer of The Savannah Bancorp
and Chief Executive Officer of The Savannah Bank, N.A., Savannah, Georgia.
Member of the Board of Directors of Thomaston Mills, Thomaston, Georgia.

Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc.,
Springfield, Georgia.

Robert B. Miller, III - President of American Building Systems, Inc., Savannah,
Georgia.

Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation.
Director of First Union Bank of Georgia, First Union
Bank of Savannah and Cerulean Corporation.

W. Miles Greer - Vice President of Customer Operations and External Affairs
since 1998. He previously served as Vice President of Marketing and Customer
Service from 1994 to 1998. Responsible for customer services, transmission and
distribution, engineering, system operation and external affairs.

Sandra R. Miller - Vice President of Power Generation since 2001. She previously
served as Manager of Technical Training at SCS from 1998 to 2001 and Team Leader
at GEORGIA's Plant Bowen from June 1996 to June 1998. Responsible for operations
and maintenance of Plants Kraft, Riverside and McIntosh.

Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since
1994 and Assistant Corporate Secretary since 1998. Responsible primarily for
accounting, financial, labor relations, corporate services, corporate
compliance, environmental and safety activities.

Involvement in certain legal proceedings.
     None

Section 16(a) Beneficial Ownership Reporting
Compliance.

     No late filers.


                                     III-2


<PAGE>

Item 11.        EXECUTIVE COMPENSATION

Summary Compensation Table. The following table sets forth information
concerning any Chief Executive Officer and the three most highly compensated
executive officers of SAVANNAH serving during 2001.
<TABLE>
<CAPTION>

                                              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
------------------------------------------------------------------------------------------------------------------------

<S>                      <C>        <C>          <C>                <C>          <C>            <C>            <C>
G. Edison
   Holland, Jr.4
President,               2001       333,539      324,022            3,692        68,071               -        49,827
Chief Executive          2000       295,812      243,263           24,438        25,667               -        15,453
Officer, Director        1999       254,914       42,626           21,588         8,375         166,052        13,392

Anthony R. James5
President, Chief         2001       210,856      177,858            1,328        31,363               -        30,195
Executive Officer,       2000       175,048      161,442                -        12,752               -         7,582
Director                 1999             -            -                -             -               -             -

W. Miles Greer           2001       184,066      104,286              666        32,505               -         8,567
Vice President           2000       177,013      100,923              601        13,416               -        16,982
                         1999       168,713       21,322            1,874         6,130          79,476        15,150

Kirby R. Willis
Vice President,          2001       168,747      100,480              490        29,993               -         8,495
Chief Financial          2000       162,279       97,394            4,908         8,785               -        12,159
Officer, Treasurer       1999       156,068       19,546              259         5,028          79,476        11,767

Sandra R. Miller6        2001       112,802       83,015            8,123         1,896               -        20,749
Vice President           2000             -            -                -             -               -             -
                         1999             -            -                -             -               -             -

-----------------------------------
1 Tax reimbursement by SAVANNAH on certain personal benefits.
2 Payouts made in 2000 for the four-year performance period ending December 31, 1999.
3 SAVANNAH contributions in 2001 to the Employee Savings Plan (ESP), Employee
Stock Ownership Plan (ESOP), Supplemental Benefit Plan (SBP) or Above-Market
Earnings on deferred compensation (AME) and tax sharing benefits paid to
participants who elected receipt of dividends on SOUTHERN's common stock held in
the ESP are as follows:
Name                          ESP        ESOP      SBP or AME   ESP Tax Sharing Benefits
----                          ---        ----      ----------   ------------------------
G. Edison Holland, Jr.      $6,853      $764       $9,861            $721
Anthony R. James             6,853       764        3,181               -
W. Miles Greer               7,650       764          153               -
Kirby R. Willis              5,923       764        1,808               -
Sandra R. Miller             5,051       698            -               -
In 2001, this amount for Mr. Holland,  Mr. James and Ms. Miller includes
$31,628,  $19,397 and $15,000,  respectively,  of additional incentive
compensation.
4 Mr. Holland transferred to SOUTHERN on May 1, 2001.
5 Mr. James became President and Chief Executive Officer effective May 1, 2001.
6 Ms. Miller became an executive officer of SAVANNAH on July 26, 2001.
</TABLE>

                                     III-3
<PAGE>

                           STOCK OPTION GRANTS IN 2001

Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of SAVANNAH during the year ending December 31,
2001.
<TABLE>
<CAPTION>


                                   Individual Grants                                         Grant Date Value

                              # of           % of Total
                              Securities     Options          Exercise
                              Underlying     Granted to       or
                              Options        Employees in     Base Price      Expiration     Grant Date
   Name                       Granted7       Fiscal Year8     ($/Sh)7         Date7          Present Value($)9
   -----------------------------------------------------------------------------------------------------------------

   SAVANNAH

<S>                             <C>                <C>          <C>           <C>                   <C>
   G. Edison Holland, Jr.       33,159             17           19.0762       2/16/2011             146,894
                                34,912             17           22.4250       4/16/2011             166,530
   Anthony R. James             17,794              9           19.0762       2/16/2011              78,827
                                13,569              7           22.4250       4/16/2011              64,724
   W. Miles Greer               17,007              8           19.0762       2/16/2011              75,341
                                15,498              8           22.4250       4/16/2011              73,925
   Kirby R. Willis              15,591              8           19.0762       2/16/2011              69,068
                                14,402              7           22.4250       4/16/2001              68,698
   Sandra R. Miller              1,337              1           19.0762       2/16/2011               5,923
                                   559              0           22.4250       4/16/2011               2,666

-------------------------------
</TABLE>

7 Under the terms of the Omnibus Incentive Compensation Plan, stock option
grants were made on February 16, 2001 and April 16, 2001, and vest annually at a
rate of one-third on the anniversary date of the grant. Grants fully vest upon
termination as a result of death, total disability or retirement and expire five
years after retirement, three years after death or total disability or their
normal expiration date if earlier. The exercise price is the average of the high
and low price of SOUTHERN's common stock on the date granted. Options may be
transferred to certain family members, family trusts and family limited
partnerships. The number of options granted on February 16, 2001 and the
exercise price thereof were adjusted after the spin-off of Mirant under the
antidilution provisions of the plan such that the options had the same aggregate
intrinsic value on the day of the spin-off as the day before.
8 A total of 200,946 stock options were granted in 2001.
9 Value was calculated using the Black-Scholes option valuation model. The
actual value, if any, ultimately realized depends on the market value of
SOUTHERN's common stock at a future date. Significant assumptions are shown
below:
<TABLE>
<CAPTION>

                                      Risk-free       Dividend                      Discount for forfeiture risk:
     Grant            Volatility    rate of return   opportunity         Term          before        after
     Date                                                                             vesting       vesting
-------------------------------------------------------------------------------------------------------------------
<S>  <C>                 <C>           <C>            <C>                <C>           <C>           <C>
     2/16/01             25.63%        4.83%          50%                10            7.79%         12.45%
     4/16/01             26.50%        4.65%          50%                10            7.79%         11.77%
-------------------------------------------------------------------------------------------------------------------


These assumptions reflect the effects of cash dividend equivalents paid to
participants under SOUTHERN's Performance Dividend Plan assuming targets are met.

</TABLE>


                                     III-4
<PAGE>

AGGREGATED STOCK OPTION EXERCISES IN 2001 AND YEAR-END OPTION VALUES

Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 2001 by the
named executive officers and the value of unexercised options held by them as of
December 31, 2001.
<TABLE>
<CAPTION>

                                                                        Number of
                                                                        Securities             Value of
                                                                        Underlying             Unexercised
                                                                        Unexercised            In-the-Money
                                                                        Options at             Options at
                                                                        Fiscal                 Fiscal
                                                                        Year-End (#)           Year-End($)10

                         Shares Acquired           Value                Exercisable/           Exercisable/
Name                     on Exercise (#)           Realized($)11        Unexercisable          Unexercisable
--------------------------------------------------------------------------------------------------------------

SAVANNAH

<S>                           <C>                    <C>                 <C>                 <C>
G. Edison Holland, Jr.        38,297                 419,217             35,004/99,611       325,235/637,703
Anthony R. James               6,757                  67,947             17,972/47,384       166,611/317,077
W. Miles Greer                     -                       -             29,132/49,916       288,866/331,185
Kirby R. Willis                6,218                  55,902             25,096/41,929       248,549/261,847
Sandra R. Miller                   -                       -                 560/3,015          5,980/21,972


----------------------------

10 This column represents the excess of the fair market value of SOUTHERN's
common stock of $25.35 per share, as of December 31, 2001, above the exercise
price of the options. The Exercisable column reports the "value" of options that
are vested and therefore could be exercised. The Unexercisable column reports
the "value" of options that are not vested and therefore could not be exercised
as of December 31, 2001.
11 The "Value Realized" is ordinary income, before taxes, and represents the
amount equal to the excess of the fair market value of the shares at the time of
exercise above the exercise price.
</TABLE>


                                     III-5
<PAGE>


                  DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE

Pension Plan Table. The following table sets forth the estimated annual pension
benefits payable at normal retirement age under SOUTHERN's qualified Pension
Plan, as well as non-qualified supplemental benefits, based on the stated
compensation and years of service with the SOUTHERN system for Ms. Miller and
Messrs. Holland and James. Compensation for pension purposes is limited to the
average of the highest three of the final 10 years' compensation. Compensation
is base salary plus the excess of annual incentive compensation over 15 percent
of base salary. These compensation components are reported under columns titled
"Salary" and "Bonus" in the Summary Compensation Table on page III-3.
<TABLE>
<CAPTION>

                                           Years of Accredited Service

Remuneration             15         20           25           30          35            40
------------             -----------------------------------------------------------------

    <S>             <C>         <C>         <C>          <C>           <C>          <C>
    $  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
</TABLE>

     As of December 31, 2001, the applicable compensation levels and years of
accredited service for SAVANNAH's named executive officers are presented in the
following table:

                                         Compensation         Accredited
            Name                             Level          Years of Service

            G. Edison Holland, Jr.12       $522,288                  18
            Anthony R. James                299,112                  22
            W. Miles Greer13                250,600                  25
            Kirby R. Willis                 235,192                  27
            Sandra R. Miller                156,036                  21

The amounts shown in the table were calculated according to the final average
pay formula and are based on a single life annuity without reduction for joint
and survivor annuities or computation of Social Security offset that would apply
in most cases.

-----------------------

12 The number of accredited years of service includes 9 years and 3 months
credited to Mr. Holland pursuant to a supplemental pension agreement.
13 The number of accredited years of service includes 7 years and 6 months
credited to Mr. Greer pursuant to a supplemental pension agreement.

                                     III-6

<PAGE>


     Effective January 1, 1998, SAVANNAH merged its pension plan into the
SOUTHERN Pension Plan. SAVANNAH also has in effect a supplemental executive
retirement plan for certain of its executive employees. The plan is designed to
provide participants with a supplemental retirement benefit, which, in
conjunction with Social Security and benefits under SOUTHERN's qualified pension
plan, will equal 70 percent of the highest three of the final 10 years' average
annual earnings (excluding incentive compensation).

      The following table sets forth the estimated combined annual pension
benefits under SOUTHERN's pension and SAVANNAH's supplemental executive
retirement plans in effect during 2001 which are payable to Messrs. Greer and
Willis, upon retirement at the normal retirement age after designated periods
of accredited service and at a specified compensation level.

                                           Years of Accredited Service
       Remuneration                  15                 25               35
--------------------------           --                 --               --

          $150,000                  105,000           105,000          105,000
           180,000                  126,000           126,000          126,000
           210,000                  147,000           147,000          147,000
           260,000                  182,000           182,000          182,000
           280,000                  196,000           196,000          196,000
           300,000                  210,000           210,000          210,000
           350,000                  245,000           245,000          245,000
           400,000                  280,000           280,000          280,000
           430,000                  301,000           301,000          301,000
           460,000                  322,000           322,000          322,000

Compensation of Directors.

     Standard Arrangements. The following table presents compensation paid to
the directors during 2001 for service as a member of the board of directors and
any board committee(s), except that employee directors received no fees or
compensation for service as a member of the board of directors or any board
committee. At the election of the director, all or a portion of the cash
retainer may be payable in SOUTHERN's common stock, and all or a portion of the
total fees may be deferred under the Deferred Compensation Plan until membership
on the board is terminated.

Cash Retainer Fee       $10,000
Stock Retainer Fee      50 shares in the first quarter 2001 and 85 shares per
                        quarter thereafter

Meeting Fees:
$750 for each Board or Committee meeting attended

     Effective January 1, 1997, the Outside Directors Pension Plan (the "Plan")
was terminated and benefits payable under the Plan were frozen. Non-employee
directors serving as of January 1, 1997 were given a one-time election to
receive a Plan benefit buy-out equal to the actuarial present value of future
Plan benefits or receive benefits under the terms of the Plan at the annual
retainer rate in effect on December 31, 1996. Directors who elected to receive
the benefit buy-out were required to defer receipt of that amount under the
Deferred Compensation Plan until termination from board membership. Directors
who elected to continue to participate under the terms of the Plan are entitled
to benefits upon retirement from the board on the retirement date designated in
SAVANNAH's by-laws. The annual benefit payable is based upon length of service
and varies from 75 percent of the annual retainer in effect on December 31, 1996
if the participant has at least 60 months of service on the board of one or more
system companies, to 100 percent if the participant has at least 120 months of
such service. Payments will continue for the greater of the lifetime of the
participant or 10 years.

                                     III-7
<PAGE>


Other Arrangements. No director received other compensation for services as
a director during the year ending December 31, 2001 in addition to or in lieu of
that specified by the standard arrangements specified above.

Employment Contracts and Termination of Employment and Change in Control
Arrangements.
------------------------------------------------------------------------

SAVANNAH has adopted SOUTHERN's Change in Control Plan, which is applicable to
certain of its officers, and has entered into individual change in control
agreements with its most highly compensated executive officers. If an executive
is involuntarily terminated, other than for cause, within two years following a
change in control of SAVANNAH or SOUTHERN, the agreements provide for:

o lump sum payment of two or three times annual compensation,
o up to five years' coverage under group health and life insurance plans,
o immediate vesting of all stock options, stock appreciation rights and
  restricted stock previously granted,
o payment of any accrued long-term and short-term bonuses and dividend
  equivalents and
o payment of any excise tax liability incurred as a result of payments
  made under any individual agreements.

A SOUTHERN change in control is defined under the agreements as:

o acquisition of at least 20 percent of the SOUTHERN's stock,
o a change in the majority of the members of the SOUTHERN's board of directors,
o a merger or other business combination that results in SOUTHERN's
  shareholders immediately before the merger owning less than 65 percent of
  the voting power after the merger or
o a sale of substantially all the assets of SOUTHERN.

A change in control of SAVANNAH is defined under the agreements as:

o acquisition of at least 50 percent of SAVANNAH's stock,
o a merger or other business combination unless SOUTHERN controls the
  surviving entity or
o a sale of substantially all the assets of SAVANNAH.

     SOUTHERN also has amended its short- and long-term incentive plans to
provide for pro-rata payments at not less than target-level performance if a
change in control occurs and the plans are not continued or replaced with
comparable plans.

Report on Repricing of Options.

         None.

Compensation Committee Interlocks and Insider Participation.

         None.
                                     III-8

<PAGE>


ITEM 12.        SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Security Ownership of Certain Beneficial Owners.  SOUTHERN is the beneficial
owner of 100% of the outstanding common stock of SAVANNAH.

-------------------------------------------------------------------------------
                                                  Amount and
                 Name and Address                 Nature of            Percent
                 of Beneficial                    Beneficial           of
Title of Class   Owner                            Ownership            Class
-------------------------------------------------------------------------------

Common Stock     The Southern Company                                    100%
                 270 Peachtree Street, N.W.
                 Atlanta, Georgia 30303

                 Registrant:
                 SAVANNAH                            10,844,635

Security Ownership of Management. The following table shows the number of shares
of SOUTHERN common stock owned by the SAVANNAH's directors, nominees and
executive officers as of December 31, 2001. It is based on information furnished
by the directors, nominees and executive officers. The shares owned by all
directors, nominees and executive officers as a group constitute less than one
percent of the total number of shares outstanding on December 31, 2001.

Name of Directors,
Nominees and                                        Number of Shares
Executive Officers          Title of Class          Beneficially Owned (1) (2)
------------------          --------------          --------------------------

Gus H. Bell, III            SOUTHERN Common                          259
Archie H. Davis             SOUTHERN Common                          522
Walter D. Gnann             SOUTHERN Common                        3,433
Anthony R. James            SOUTHERN Common                       43,854
Robert B. Miller, III       SOUTHERN Common                        1,128
Arnold M. Tenenbaum         SOUTHERN Common                        1,167
W. Miles Greer              SOUTHERN Common                       46,348
Sandra R. Miller            SOUTHERN Common                        3,365
Kirby R. Willis             SOUTHERN Common                       40,712

The directors, nominees
and executive officers
as a group                  SOUTHERN Common                      140,788



(1)    As used in this table, "beneficial ownership" means the sole or shared
       power to vote, or to direct the voting of, a security and/or investment
       power with respect to a security (i.e., the power to dispose of, or to
       direct the disposition of, a security).

(2)    The shares shown include shares of SOUTHERN common stock of which certain
       directors and executive officers have the right to acquire beneficial
       ownership within 60 days pursuant to the Executive Stock Plan and/or
       Performance Stock Plan, as follows: Mr. Greer, 41,887 shares; Mr. James,
       30,640 shares, Ms. Miller, 1,565 shares and Mr. Willis, 34,933 shares.

                                     III-9
<PAGE>


Changes in control. SOUTHERN and SAVANNAH know of no arrangements which may at a
subsequent date result in any change in control.


ITEM 13.        CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with management and others.

     Mr. Archie Davis is currently Chief Executive Officer of The Savannah Bank,
N.A., Savannah, Georgia and was also President prior to February 2002. During
2001, this bank furnished a number of regular banking services in the ordinary
course of business to SAVANNAH. SAVANNAH intends to maintain normal banking
relations with the aforesaid bank in the future.

Certain business relationships.
     None.

Indebtedness of management.
     None.

Transactions with promoters.
     None.




                                     III-10


<PAGE>

                                     PART IV


Item 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) The following documents are filed as a part of this report on this
    Form 10-K:

     (1) Financial Statements:

         Reports of Independent Public Accountants on the financial statements
         for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF,
         MISSISSIPPI and SAVANNAH are listed under Item 8 herein.

         The financial statements filed as a part of this report for SOUTHERN
         and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
         SAVANNAH are listed under Item 8 herein.

     (2) Financial Statement Schedules:

         Reports of Independent Public Accountants as to Schedules for SOUTHERN
         and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
         SAVANNAH are included herein on pages IV-12 through IV-17.

         Financial Statement Schedules for SOUTHERN and Subsidiary Companies,
         ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed in the
         Index to the Financial Statement Schedules at page S-1.

     (3) Exhibits:

         Exhibits for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
         SAVANNAH are listed in the Exhibit Index at page E-1.


(b)  Reports on Form 8-K during the fourth quarter of 2001 were as follows:


     SOUTHERN filed a Current Report on Form 8-K:

     Date of event:        December 20, 2001
     Items reported:       Item 5

     GEORGIA filed a Current Report on Form 8-K:

     Date of event:        December 20, 2001
     Items reported:       Item 5

     GULF filed Current Reports on Form 8-K:

     Date of event:        October 5, 2001
     Items reported:       Items 5 and 7

     Date of event:        November 8, 2001
     Items reported:       Items 5 and 7


                                      IV-1
<PAGE>
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     THE SOUTHERN COMPANY

     By:   H. Allen Franklin, Chairman, President and
           Chief Executive Officer

        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     H. Allen Franklin
     Chairman, President and
     Chief Executive Officer
     (Principal Executive Officer)

     Gale E. Klappa
     Executive Vice President, Chief Financial Officer and
     Treasurer
     (Principal Financial Officer)

     W. Dean Hudson
     Comptroller and Chief Accounting Officer
     (Principal Accounting Officer)


                            Directors:
    Daniel P. Amos                L. G. Hardman III
    Dorrit J. Bern                Donald M. James
    Thomas F. Chapman             Zack T. Pate
    Bruce S. Gordon               Gerald J. St. Pe'


        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     ALABAMA POWER COMPANY

     By:   Charles D. McCrary, President and
           Chief Executive Officer

        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     Charles D. McCrary
     President, Chief Executive Officer and Director
     (Principal Executive Officer)

     William B. Hutchins, III
     Executive Vice President, Chief Financial Officer and Treasurer
     (Principal Financial Officer)

     Art P. Beattie
     Vice President and Comptroller
     (Principal Accounting Officer)

                          Directors:
    Whit Armstrong                     Mayer Mitchell
    David J. Cooper                    William V. Muse
    H. Allen Franklin                  Robert D. Powers
    R. Kent Henslee                    C. Dowd Ritter
    Patricia M. King                   James H. Sanford
    James K. Lowder                    John Cox Webb, IV
    Wallace D. Malone, Jr.             James W. Wright
    Thomas C. Meredith

        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

                                      IV-2

<PAGE>


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     GEORGIA POWER COMPANY

     By:   David M. Ratcliffe, President and
           Chief Executive Officer

     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     David M. Ratcliffe
     President, Chief Executive Officer and Director
     (Principal Executive Officer)

     Thomas A. Fanning
     Executive Vice President, Chief Financial Officer
     and Treasurer
     (Principal Financial Officer)

     Cliff S. Thrasher
     Vice President, Comptroller and Chief Accounting Officer
     (Principal Accounting Officer)

                          Directors:
     Juanita P. Baranco           James R. Lientz, Jr.
     Anna R. Cablik               Richard W. Ussery
     William A. Fickling, Jr.     William Jerry Vereen
     H. Allen Franklin            Carl Ware
     L. G. Hardman III            E. Jenner Wood, III


         /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     GULF POWER COMPANY

     By:   Travis J. Bowden, President and
           Chief Executive Officer

        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     Travis J. Bowden
     President, Chief Executive Officer and Director
     (Principal Executive Officer)

     Ronnie R. Labrato
     Vice President, Chief Financial Officer and Comptroller
     (Principal Financial and Accounting Officer)

                        Directors:
     C. LeDon Anchors           W. Deck Hull, Jr.
     Fred C. Donovan, Sr.       William A. Pullum
     H. Allen Franklin          Joseph K. Tannehill

     By:  /s/ Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

                                      IV-3


<PAGE>
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     MISSISSIPPI POWER COMPANY

     By:   Michael D. Garrett, President and
           Chief Executive Officer

        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

     Michael D. Garrett
     President, Chief Executive Officer and Director
     (Principal Executive Officer)

     Michael W. Southern
     Vice President, Treasurer and
     Chief Financial Officer
     (Principal Financial and Accounting Officer)

                         Directors:
      Tommy E. Dulaney          George A. Schloegel
      Aubrey K. Lucas           Gene Warr
      Malcolm Portera

        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

     SAVANNAH ELECTRIC AND POWER COMPANY

     By:   Anthony R. James, President and
           Chief Executive Officer

           /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

      Anthony R. James
      President, Chief Executive Officer and Director
      (Principal Executive Officer)

      Kirby R. Willis
      Vice President, Treasurer and
      Chief Financial Officer
      (Principal Financial and Accounting Officer)

                        Directors:
     Gus H. Bell, III         Robert B. Miller, III
     Archie H. Davis          Arnold M. Tenenbaum
     Walter D. Gnann

        /s/Wayne Boston
     By:   Wayne Boston
           (Wayne Boston, Attorney-in-fact)

     Date: March 22, 2002




                                      IV-4


<PAGE>
Exhibit 21.  Subsidiaries of the Registrants.*

                                                             Jurisdiction of
Name of Company                                                Organization
-------------------------------------------------------------------------------

The Southern Company                                          Delaware
         Southern Company Capital Trust I                     Delaware
         Southern Company Capital Trust II                    Delaware
         Southern Company Capital Trust III                   Delaware
         Southern Company Capital Trust IV                    Delaware
         Southern Company Capital Trust V                     Delaware
         Southern Company Capital Trust VI                    Delaware
         Southern Company Capital Trust VII                   Delaware
         Southern Company Capital Trust VIII                  Delaware
         Southern Company Capital Trust IX                    Delaware
Alabama Power Company                                         Alabama
         Alabama Power Capital Trust I                        Delaware
         Alabama Power Capital Trust II                       Delaware
         Alabama Power Capital Trust III                      Delaware
         Alabama Power Capital Trust IV                       Delaware
         Alabama Power Capital Trust V                        Delaware
         Alabama Property Company                             Alabama
         Southern Electric Generating Company                 Alabama
Georgia Power Company                                         Georgia
         Georgia Power Capital Trust I                        Delaware
         Georgia Power Capital Trust II                       Delaware
         Georgia Power Capital Trust III                      Delaware
         Georgia Power Capital Trust IV                       Delaware
         Georgia Power Capital Trust V                        Delaware
         Georgia Power Capital Trust VI                       Delaware
         Georgia Power Capital Trust VII                      Delaware
         Georgia Power Capital Trust VIII                     Delaware
         Piedmont-Forrest Corporation                         Georgia
         Southern Electric Generating Company                 Alabama
Gulf Power Company                                            Maine
         Gulf Power Capital Trust I                           Delaware
         Gulf Power Capital Trust II                          Delaware
         Gulf Power Capital Trust III                         Delaware
         Gulf Power Capital Trust IV                          Delaware
Mississippi Power Company                                     Mississippi
         Mississippi Power Capital Trust I                    Delaware
         Mississippi Power Capital Trust II                   Delaware
         Mississippi Power Capital Trust III                  Delaware
Savannah Electric and Power Company                           Georgia
         Savannah Electric Capital Trust I                    Delaware
         Savannah Electric Capital Trust II                   Delaware
Southern Power Company                                        Delaware
-------------------------------------------------------------------------------

*This information is as of December 31, 2001. In addition, this list omits
certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K, Item
601.

                                  IV-5

<PAGE>
                                                                Exhibit 23(a)

                 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS




         As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of The Southern Company and its subsidiaries and the related financial statement
schedule, included in this Form 10-K, into The Southern Company's previously
filed Registration Statement File Nos. 2-78617, 33-3546, 33-54415, 33-57951,
33-58371, 33-60427, 333-09077, 333-31808, 333-44127, 333-44261, 333-64871,
333-65178 and 333-73462.





/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002
                                      IV-6

<PAGE>

                                                                  Exhibit 23(b)


                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





         As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Alabama Power Company and the related financial statement schedule, included
in this Form 10-K, into Alabama Power Company's previously filed Registration
Statement File No. 333-72784.




/s/Arthur Andersen LLP
Birmingham, Alabama
March 19, 2002

                                      IV-7
<PAGE>
                                                                 Exhibit 23(c)


                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





         As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Georgia Power Company and the related financial statement schedule, included
in this Form 10-K, into Georgia Power Company's previously filed Registration
Statement File Nos. 333-75193 and 333-57884.





/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002

                                      IV-8
<PAGE>

                                                              Exhibit 23(d)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





         As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Gulf Power Company and the related financial statement schedule, included in
this Form 10-K, into Gulf Power Company's previously filed Registration
Statement File No. 333-59942.




/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002

                                      IV-9
<PAGE>

                                                              Exhibit 23(e)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





         As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Mississippi Power Company and the related financial statement schedule,
included in this Form 10-K, into Mississippi Power Company's previously filed
Registration Statement File No. 333-45069.





/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002

                                     IV-10
<PAGE>

                                                               Exhibit 23(f)





                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS





         As independent public accountants, we hereby consent to the
incorporation of our reports dated February 13, 2002 on the financial statements
of Savannah Electric and Power Company and the related financial statement
schedule, included in this Form 10-K, into Savannah Electric and Power Company's
previously filed Registration Statement File No. 333-57886.




/s/Arthur Andersen LLP
Atlanta, Georgia
March 19, 2002


                                     IV-11

<PAGE>




REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To The Southern Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the consolidated financial statements of The Southern Company
and its subsidiaries included in this Form 10-K, and have issued our report
thereon dated February 13, 2002. Our audits were made for the purpose of forming
an opinion on those statements taken as a whole. The schedule listed under Item
14(a)(2) herein as it relates to The Southern Company and its subsidiaries (page
S-2) is the responsibility of The Southern Company's management and is presented
for purposes of complying with the Securities and Exchange Commission's rules
and is not part of the basic consolidated financial statements. This schedule
has been subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.




/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002

                                     IV-12
<PAGE>




REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Alabama Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Alabama Power Company included in
this Form 10-K, and have issued our report thereon dated February 13, 2002. Our
audits were made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed under Item 14(a)(2) herein as it relates to
Alabama Power Company (page S-3) is the responsibility of Alabama Power
Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.




/s/Arthur Andersen LLP
Birmingham, Alabama
February 13, 2002

                                     IV-13
<PAGE>




REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Georgia Power Company:

      We have audited in accordance with auditing standards generally accepted
in the United States, the financial statements of Georgia Power Company included
in this Form 10-K, and have issued our report thereon dated February 13, 2002.
Our audits were made for the purpose of forming an opinion on those statements
taken as a whole. The schedule listed under Item 14(a)(2) herein as it relates
to Georgia Power Company (page S-4) is the responsibility of Georgia Power
Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.




/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002

                                     IV-14

<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Gulf Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Gulf Power Company included in
this Form 10-K, and have issued our report thereon dated February 13, 2002. Our
audits were made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed under Item 14(a)(2) herein as it relates to Gulf
Power Company (page S-5) is the responsibility of Gulf Power Company's
management and is presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic financial statements.
This schedule has been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion, fairly states in
all material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.




/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002

                                     IV-15


<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Mississippi Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Mississippi Power Company
included in this Form 10-K, and have issued our report thereon dated February
13, 2002. Our audits were made for the purpose of forming an opinion on those
statements taken as a whole. The schedule listed under Item 14(a)(2) herein as
it relates to Mississippi Power Company (page S-6) is the responsibility of
Mississippi Power Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.




/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002

                                     IV-16
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE


To Savannah Electric and Power Company:

    We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Savannah Electric and Power
Company included in this Form 10-K, and have issued our report thereon dated
February 13, 2002. Our audits were made for the purpose of forming an opinion on
those statements taken as a whole. The schedule listed under Item 14(a)(2)
herein as it relates to Savannah Electric and Power Company (page S-7) is the
responsibility of Savannah Electric and Power Company's management and is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.




/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002

                                     IV-17

<PAGE>

                     INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule

II     Valuation and Qualifying Accounts and Reserves
        2001, 2000 and 1999
         The Southern Company and Subsidiary Companies...................   S-2
         Alabama Power Company...........................................   S-3
         Georgia Power Company...........................................   S-4
         Gulf Power Company..............................................   S-5
         Mississippi Power Company.......................................   S-6
         Savannah Electric and Power Company.............................   S-7

    Schedules I through V not listed above are omitted as not applicable or not
required. Columns omitted from schedules filed have been omitted because the
information is not applicable or not required.

                                      S-1
<PAGE>
<TABLE>
<CAPTION>



                                              THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
                                             SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                           FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                                                     (Stated in Thousands of Dollars)

                                                                           Additions
                                                                 ----------------------------------------

                                   Balance at Beginning     Charged to     Charged to Other                      Balance at End
         Description                     of Period             Income           Accounts       Deductions            of Period
  -------------------------------- ------------------------ -------------- ------------------- ----------------- --------------
  Provision for uncollectible
     accounts
       <S>                                 <C>                <C>                 <C>            <C>                   <C>
       2001.....................           $21,799            $44,272             $269           $41,957 (Note)        $24,383
       2000.....................            21,834             31,329               39            31,403 (Note)         21,799
       1999.....................            11,268             35,476                -            24,910 (Note)         21,834

-------------------
Note:    Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
</TABLE>
                                       S-2

<PAGE>
<TABLE>
<CAPTION>



                                                           ALABAMA POWER COMPANY
                                              SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                            FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                                                      (Stated in Thousands of Dollars)

                                                                            Additions
                                                                  ---------------------------------------

                                       Balance at Beginning    Charged to      Charged to Other                     Balance at End
         Description                         of Period            Income            Accounts        Deductions          of Period
  ------------------------------------ ----------------------- --------------- ------------------ ----------------- ---------------
  Provision for uncollectible
    accounts
       <S>                                    <C>                  <C>                <C>            <C>                  <C>
       2001..........................         $6,237               $7,419             $-             $8,419 (Note)        $5,237
       2000..........................          4,117                9,093              -              6,973 (Note)         6,237
       1999..........................          1,855               13,995              -             11,733 (Note)         4,117

-------------------
Note:  Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

</TABLE>
                                      S-3
<PAGE>
<TABLE>
<CAPTION>



                                                         GEORGIA POWER COMPANY
                                            SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                          FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                                                    (Stated in Thousands of Dollars)

                                                                        Additions
                                                              ---------------------------------------

                                      Balance at Beginning    Charged to     Charged to Other                     Balance at End
         Description                        of Period            Income           Accounts        Deductions          of Period
  ----------------------------------- ----------------------- -------------- ------------------ ----------------- ----------------
  Provision for uncollectible
    accounts
       <S>                                    <C>               <C>                <C>            <C>                  <C>
       2001..........................         $5,100            $22,913             $-             $19,118 (Note)        $8,895
       2000..........................          7,000             10,794              -              12,694 (Note)         5,100
       1999..........................          5,500             14,406              -              12,906 (Note)         7,000

-------------------
Note:  Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
</TABLE>

                                      S-4
<PAGE>
<TABLE>
<CAPTION>



                                                           GULF POWER COMPANY
                                             SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                          FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                                                    (Stated in Thousands of Dollars)

                                                                          Additions
                                                                --------------------------------------

                                       Balance at Beginning     Charged to      Charged to Other                    Balance at End
         Description                         of Period             Income            Accounts      Deductions           of Period
  ------------------------------------ ------------------------ --------------- ------------------ ---------------- ---------------
  Provision for uncollectible
    accounts
       <S>                                    <C>                  <C>                 <C>           <C>                <C>
       2001..........................         $1,302               $2,282               $-           $2,242(Note)       $1,342
       2000..........................          1,026                2,702                -            2,426(Note)        1,302
       1999..........................            996                2,230                -            2,200(Note)        1,026

-------------------
Note:  Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

</TABLE>
                                      S-5

<PAGE>
<TABLE>
<CAPTION>



                                                        MISSISSIPPI POWER COMPANY
                                             SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                          FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                                                    (Stated in Thousands of Dollars)

                                                                           Additions
                                                                 --------------------------------------

                                       Balance at Beginning      Charged to     Charged to Other                    Balance at End
         Description                         of Period              Income           Accounts      Deductions           of Period
  ------------------------------------ ------------------------- -------------- ------------------ ---------------- ---------------
  Provision for uncollectible
    accounts
       <S>                                      <C>                 <C>               <C>            <C>                  <C>
       2001..........................           $571                $2,877           $(165)          $2,427 (Note)        $856
       2000..........................            697                 1,156              14            1,296 (Note)         571
       1999..........................            621                 1,964               -            1,888 (Note)         697


-------------------
Note:  Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
</TABLE>
                                      S-6

<PAGE>
<TABLE>
<CAPTION>



                                                  SAVANNAH ELECTRIC AND POWER COMPANY
                                            SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                                         FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                                                   (Stated in Thousands of Dollars)

                                                                          Additions
                                                                -------------------------------------

                                         Balance at Beginning   Charged to   Charged to Other                   Balance at End
         Description                           of Period           Income         Accounts      Deductions          of Period
  -------------------------------------- ---------------------- ------------ ------------------ --------------- -----------------
  Provision for uncollectible
    accounts
       <S>                                        <C>                <C>            <C>          <C>                  <C>
       2001..........................             $407               $978           $-            $885 (Note)         $500
       2000..........................              237                999            -             829 (Note)          407
       1999..........................              284                594            -             641 (Note)          237

-------------------
Note:  Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously
written off.
</TABLE>


                                      S-7
<PAGE>

                                  EXHIBIT INDEX

    The following exhibits indicated by an asterisk preceding the exhibit number
are filed herewith. The balance of the exhibits have heretofore been filed with
the SEC as the exhibits and in the file numbers indicated and are incorporated
herein by reference. The exhibits marked with a pound sign are management
contracts or compensatory plans or arrangements required to be filed herewith
and required to be identified as such by Item 14 of Form 10-K. Reference is made
to a duplicate list of exhibits being filed as a part of this Form 10-K, which
list, prepared in accordance with Item 601 of Regulation S-K of the SEC,
immediately precedes the exhibits being physically filed with this Form 10-K.

(3)      Articles of Incorporation and By-Laws

         SOUTHERN

         (a)  1 - Composite Certificate of Incorporation of SOUTHERN,
                  reflecting all amendments thereto through January 5, 1994.
                  (Designated in Registration No. 33-3546 as Exhibit 4(a), in
                  Certificate of Notification, File No. 70-7341, as Exhibit A
                  and in Certificate of Notification, File No. 70-8181, as
                  Exhibit A.)

         (a)  2 - By-laws of SOUTHERN as amended effective October 21, 1991,
                  and as presently in effect. (Designated in Form U-1, File No.
                  70-8181, as Exhibit A-2.)


         ALABAMA

         (b)  1 - Charter of ALABAMA and amendments thereto through January
                  10, 2001. (Designated in Registration Nos. 2-59634 as Exhibit
                  2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b),
                  2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539
                  as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K
                  dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in
                  Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit
                  4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164,
                  as Exhibits 4(a) and 4(b), in Form 8-K dated November 16,
                  1993, File No. 1-3164, as Exhibit 4(a), in Certificate of
                  Notification, File No. 70-8191, as Exhibit A, in ALABAMA's
                  Form 10-K for the year ended December 31, 1997, File No.
                  1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998,
                  File No. 1-3164, as Exhibit 4.4 and in ALABAMA's Form 10-K for
                  the year ended December 31, 2000, File No. 1-3164, as Exhibit
                  3(b)2.)

        *(b)  2 - Amendment to Charter of ALABAMA dated November 21,
                  2001.

        *(b)  3 - By-laws of ALABAMA as amended effective April 26,
                  2001, and as presently in effect.

         GEORGIA

         (c)  1 - Charter of GEORGIA and amendments thereto through January
                  16, 2001. (Designated in Registration Nos. 2-63392 as Exhibit
                  2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as
                  Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit
                  4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit
                  4(b)(2), 33-


                                      E-1
<PAGE>


                  14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits
                  4(b)-(2), 4(b)-(3) and 4(b)-(4), in GEORGIA's Form 10-K for
                  the year ended December 31, 1991, File No. 1-6468, as Exhibits
                  4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits
                  4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992,
                  File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17,
                  1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated
                  October 20, 1993, File No. 1-6468, as Exhibit 4(b), in
                  GEORGIA's Form 10-K for the year ended December 31, 1997, File
                  No. 1-6468, as Exhibit 3(c)2 and in GEORGIA's Form 10-K for
                  the year ended December 31, 2000, File No. 1-6468, as Exhibit
                  3(c)2.)

         (c)  2 - By-laws of GEORGIA as amended effective November 15, 2000,
                  and as presently in effect. (Designated in GEORGIA's Form 10-K
                  for the year ended December 31, 2000, File No. 1-6468, as
                  Exhibit 3(c)3.)


         GULF

         (d)  1 - Restated Articles of Incorporation of GULF and amendments
                  thereto through February 9, 2001. (Designated in Registration
                  No. 33-43739 as Exhibit 4(b)-1, in Form 8-K dated January 15,
                  1992, File No. 0-2429, as Exhibit 1(b), in Form 8-K dated
                  August 18, 1992, File No. 0-2429, as Exhibit 4(b)-2, in Form
                  8-K dated September 22, 1993, File No. 0-2429, as Exhibit 4,
                  in Form 8-K dated November 3, 1993, File No. 0-2429, as
                  Exhibit 4, in GULF's Form 10-K for the year ended December 31,
                  1997, File No. 0-2429, as Exhibit 3(d)2 and in GULF's Form
                  10-K for the year ended December 31, 2000, File No. 0-2429, as
                  Exhibit 3(d)2.)

        *(d)  2 - By-laws of GULF as amended effective May 22, 2001, and
                  as presently in effect.


         MISSISSIPPI

         (e)  1 - Articles of Incorporation of MISSISSIPPI, articles of
                  merger of Mississippi Power Company (a Maine corporation) into
                  MISSISSIPPI and articles of amendment to the articles of
                  incorporation of MISSISSIPPI through March 8, 2001.
                  (Designated in Registration No. 2-71540 as Exhibit 4(a)-1, in
                  Form U5S for 1987, File No. 30-222-2, as Exhibit B-10, in
                  Registration No. 33-49320 as Exhibit 4(b)-(1), in Form 8-K
                  dated August 5, 1992, File No. 0-6849, as Exhibits 4(b)-2 and
                  4(b)-3, in Form 8-K dated August 4, 1993, File No. 0-6849, as
                  Exhibit 4(b)-3, in Form 8-K dated August 18, 1993, File No.
                  0-6849, as Exhibit 4(b)-3, in MISSISSIPPI's Form 10-K for the
                  year ended December 31, 1997, File No. 0-6849, as Exhibit
                  3(e)2 and in MISSISSIPPI's Form 10-K for the year ended
                  December 31, 2000, File No. 0-6849, as Exhibit 3(e)2.)

        *(e)  2 - By-laws of MISSISSIPPI as amended effective February
                  28, 2001, and as presently in effect.




                                      E-2
<PAGE>


         SAVANNAH

         (f)  1 - Charter of SAVANNAH and amendments thereto through
                  December 2, 1998. (Designated in Registration Nos. 33-25183 as
                  Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2), in Form 8-K
                  dated November 9, 1993, File No. 1-5072, as Exhibit 4(b) and
                  in SAVANNAH's Form 10-K for the year ended December 31, 1998,
                  as Exhibit 3(f)2.)

         (f)  2 - By-laws of SAVANNAH as amended effective May 17, 2000, and
                  as presently in effect. (Designated in SAVANNAH's Form 10-K
                  for the year ended December 31, 2000, File No. 1-5072, as
                  Exhibit 3(f)2.)


(4)   Instruments Describing Rights of Security Holders, Including Indentures

         SOUTHERN

         (a)  1 - Subordinated Note Indenture dated as of February 1, 1997,
                  among SOUTHERN, Southern Company Capital Funding, Inc. and
                  Bankers Trust Company, as Trustee, and indentures supplemental
                  thereto dated as of February 4, 1997. (Designated in
                  Registration Nos. 333-28349 as Exhibits 4.1 and 4.2 and
                  333-28355 as Exhibit 4.2.)

         (a)  2 - Subordinated Note Indenture dated as of June 1, 1997,
                  among SOUTHERN, Southern Company Capital Funding, Inc. and
                  Bankers Trust Company, as Trustee, and indentures supplemental
                  thereto through December 23, 1998. (Designated in SOUTHERN's
                  Form 10-K for the year ended December 31, 1997, File No.
                  1-3526, as Exhibit (4)(a)2, in Form 8-K dated June 18, 1998,
                  File No. 1-3526, as Exhibit 4.2 and in Form 8-K dated December
                  18, 1998, File No. 1-3526, as Exhibit 4.4.)

         (a)  3 - Senior Note Indenture dated as of February 1, 2002, among
                  SOUTHERN, Southern Company Capital Funding, Inc. and The Bank
                  of New York, as Trustee, and indentures supplemental thereto
                  through those dated February 1, 2002. (Designated in Form 8-K
                  dated January 29, 2002, File No. 1-3526, as Exhibits 4.1 and
                  4.2 and in Form 8-K dated January 30, 2002, File No. 1-3526,
                  as Exhibit 4.2.)

         (a)  4 - Amended and Restated Trust Agreement of Southern Company
                  Capital Trust I dated as of February 1, 1997. (Designated in
                  Registration No. 333-28349 as Exhibit 4.6)

         (a)  5 - Amended and Restated Trust Agreement of Southern Company
                  Capital Trust II dated as of February 1, 1997. (Designated in
                  Registration No. 333-28355 as Exhibit 4.6)

         (a)  6 - Amended and Restated Trust Agreement of Southern Company
                  Capital Trust III dated as of June 1, 1997. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 1997,
                  File No. 1-3526, as Exhibit (4)(a)5.)

         (a)  7 - Amended and Restated Trust Agreement of Southern Company
                  Capital Trust IV dated as of June 1, 1998. (Designated in Form
                  8-K dated June 18, 1998, File No. 1-3526, as Exhibit 4.5.)



                                      E-3
<PAGE>



         (a)  8 - Amended and Restated Trust Agreement of Southern Company
                  Capital Trust V dated as of December 1, 1998. (Designated in
                  Form 8-K dated December 18, 1998, File No. 1-3526, as Exhibit
                  4.7A.)

         (a)  9 - Capital Securities Guarantee Agreement relating to
                  Southern Company Capital Trust I dated as of February 1, 1997.
                  (Designated in Registration No. 333-28349 as Exhibit 4.10)

         (a) 10 - Capital Securities Guarantee Agreement relating to
                  Southern Company Capital Trust II dated as of February 1,
                  1997. (Designated in Registration No. 333-28355 as Exhibit
                  4.10)

         (a) 11 - Preferred Securities Guarantee Agreement relating to
                  Southern Company Capital Trust III dated as of June 1, 1997.
                  (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 1997, File No. 1-3526, as Exhibit (4)(a)8.)

         (a) 12 - Preferred Securities Guarantee Agreement relating to
                  Southern Company Capital Trust IV dated as of June 1, 1998.
                  (Designated in Form 8-K dated June 18, 1998, File No. 1-3626,
                  as Exhibit 4.8.)

         (a) 13 - Preferred Securities Guarantee Agreement relating to
                  Southern Company Capital Trust V dated as of December 1, 1998.
                  (Designated in Form 8-K dated December 18, 1998, File No.
                  1-3526, as Exhibit 4.11A.)


         ALABAMA

         (b)  1 - Indenture dated as of January 1, 1942, between ALABAMA and
                  JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as
                  Trustee, and indentures supplemental thereto through December
                  1, 1994. (Designated in Registration Nos. 2-59843 as Exhibit
                  2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as
                  Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit
                  2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2,
                  2-73727 as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083
                  as Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in ALABAMA's
                  Form 10-K for the year ended December 31, 1990, File No.
                  1-3164, as Exhibit 4(c), in Registration Nos. 33-43917 as
                  Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as
                  Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated
                  January 20, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form
                  8-K dated February 17, 1993, File No. 1-3164, as Exhibit
                  4(a)-3, in Form 8-K dated March 10, 1993, File No. 1-3164, as
                  Exhibit 4(a)-3, in Certificate of Notification, File No.
                  70-8069, as Exhibits A and B, in Form 8-K dated June 24, 1993,
                  File No. 1-3164, as Exhibit 4, in Certificate of Notification,
                  File No. 70-8069, as Exhibit A, in Form 8-K dated November 16,
                  1993, File No. 1-3164, as Exhibit 4(b), in Certificate of
                  Notification, File No. 70-8069, as Exhibits A and B, in
                  Certificate of Notification, File No. 70-8069, as Exhibit A,
                  in Certificate of Notification, File No. 70-8069, as Exhibit A
                  and in Form 8-K dated November 30, 1994, File No. 1-3164, as
                  Exhibit 4.)




                                      E-4
<PAGE>


         (b)  2 - Subordinated Note Indenture dated as of January 1, 1996,
                  between ALABAMA and JPMorgan Chase Bank (formerly The Chase
                  Manhattan Bank), as Trustee, and indenture supplemental
                  thereto dated as of January 1, 1996. (Designated in
                  Certificate of Notification, File No. 70-8461, as Exhibits E
                  and F.)

         (b)  3 - Subordinated Note Indenture dated as of January 1, 1997,
                  between ALABAMA and JPMorgan Chase Bank (formerly The Chase
                  Manhattan Bank), as Trustee, and indentures supplemental
                  thereto through February 25, 1999. (Designated in Form 8-K
                  dated January 9, 1997, File No. 1-3164, as Exhibits 4.1 and
                  4.2 and in Form 8-K dated February 18, 1999, File No. 3164, as
                  Exhibit 4.2.)

         (b)  4 - Senior Note Indenture dated as of December 1, 1997,
                  between ALABAMA and JPMorgan Chase Bank (formerly The Chase
                  Manhattan Bank), as Trustee, and indentures supplemental
                  thereto through August 29, 2001. (Designated in Form 8-K dated
                  December 4, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in
                  Form 8-K dated February 20, 1998, File No. 1-3164, as Exhibit
                  4.2, in Form 8-K dated April 17, 1998, File No. 1-3164, as
                  Exhibit 4.2, in Form 8-K dated August 11, 1998, File No.
                  1-3164, as Exhibit 4.2, in Form 8-K dated September 8, 1998,
                  File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September
                  16, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated
                  October 7, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K
                  dated October 28, 1998, File No. 1-3164, as Exhibit 4.2, in
                  Form 8-K dated November 12, 1998, File No. 1-3164, as Exhibit
                  4.2, in Form 8-K dated May 19, 1999, File No. 1-3164, as
                  Exhibit 4.2, in Form 8-K dated August 13, 1999, File No.
                  1-3164, as Exhibit 4.2, in Form 8-K dated September 21, 1999,
                  File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 11,
                  2000, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated
                  August 22, 2001, File No. 1-3164, as Exhibits 4.2(a) and
                  4.2(b).)

         (b)  5 - Amended and Restated Trust Agreement of Alabama Power
                  Capital Trust I dated as of January 1, 1996. (Designated in
                  Certificate of Notification, File No. 70-8461, as Exhibit D.)

         (b)  6 - Amended and Restated Trust Agreement of Alabama Power
                  Capital Trust II dated as of January 1, 1997. (Designated in
                  Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibit
                  4.5.)

         (b)  7 - Amended and Restated Trust Agreement of Alabama Power
                  Capital Trust III dated as of February 1, 1999. (Designated in
                  Form 8-K dated February 18, 1999, File No. 1-3164, as Exhibit
                  4.5.)

         (b)  8 - Guarantee Agreement relating to Alabama Power Capital
                  Trust I dated as of January 1, 1996. (Designated in
                  Certificate of Notification, File No. 70-8461, as Exhibit G.)

         (b)  9 - Guarantee Agreement relating to Alabama Power Capital
                  Trust II dated as of January 1, 1997. (Designated in Form 8-K
                  dated January 9, 1997, File No. 1-3164, as Exhibit 4.8.)

         (b) 10 - Guarantee Agreement relating to Alabama Power Capital
                  Trust III dated as of February 1, 1999. (Designated in Form
                  8-K dated February 18, 1999, File No. 1-3164, as Exhibit 4.8.)




                                      E-5
<PAGE>



         GEORGIA

         (c)  1 - Indenture dated as of March 1, 1941, between GEORGIA and
                  JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as
                  Trustee, and indentures supplemental thereto dated as of March
                  1, 1941, March 3, 1941 (3 indentures), March 6, 1941 (139
                  indentures), March 1, 1946 (88 indentures) and December 1,
                  1947, through October 15, 1995. (Designated in Registration
                  Nos. 2-4663 as Exhibits B-3 and B-3(a), 2-7299 as Exhibit
                  7(a)-2, 2-61116 as Exhibit 2(a)-3 and 2(a)-4, 2-62488 as
                  Exhibit 2(a)-3, 2-63393 as Exhibit 2(a)-4, 2-63705 as Exhibit
                  2(a)-3, 2-68973 as Exhibit 2(a)-3, 2-70679 as Exhibit
                  4(a)-(2), 2-72324 as Exhibit 4(a)-2, 2-73987 as Exhibit
                  4(a)-(2), 2-77941 as Exhibits 4(a)-(2) and 4(a)-(3), 2-79336
                  as Exhibit 4(a)-(2), 2-81303 as Exhibit 4(a)-(2), 2-90105 as
                  Exhibit 4(a)-(2), 33-5405 as Exhibit 4(a)-(2), 33-14367 as
                  Exhibits 4(a)-(2) and 4(a)-(3), 33-22504 as Exhibits 4(a)-(2),
                  4(a)-(3) and 4(a)-(4), 33-32420 as Exhibit 4(a)-(2), 33-35683
                  as Exhibit 4(a)-(2), in GEORGIA's Form 10-K for the year ended
                  December 31, 1990, File No. 1-6468, as Exhibit 4(a)(3), in
                  Form 10-K for the year ended December 31, 1991, File No.
                  1-6468, as Exhibit 4(a)(5), in Registration No. 33-48895 as
                  Exhibit 4(a)-(2), in Form 8-K dated August 26, 1992, File No.
                  1-6468, as Exhibit 4(a)-(3), in Form 8-K dated September 9,
                  1992, File No. 1-6468, as Exhibits 4(a)-(3) and 4(a)-(4), in
                  Form 8-K dated September 23, 1992, File No. 1-6468, as Exhibit
                  4(a)-(3), in Form 8-A dated October 12, 1992, as Exhibit 2(b),
                  in Form 8-K dated January 27, 1993, File No. 1-6468, as
                  Exhibit 4(a)-(3), in Registration No. 33-49661 as Exhibit
                  4(a)-(2), in Form 8-K dated July 26, 1993, File No. 1-6468, as
                  Exhibit 4, in Certificate of Notification, File No. 70-7832,
                  as Exhibit M, in Certificate of Notification, File No.
                  70-7832, as Exhibit C, in Certificate of Notification, File
                  No. 70-7832, as Exhibits K and L, in Certificate of
                  Notification, File No. 70-8443, as Exhibit C, in Certificate
                  of Notification, File No. 70-8443, as Exhibit C, in
                  Certificate of Notification, File No. 70-8443, as Exhibit E,
                  in Certificate of Notification, File No. 70-8443, as Exhibit
                  E, in Certificate of Notification, File No. 70-8443, as
                  Exhibit E, in GEORGIA's Form 10-K for the year ended December
                  31, 1994, File No. 1-6468, as Exhibits 4(c)2 and 4(c)3, in
                  Certificate of Notification, File No. 70-8443, as Exhibit C,
                  in Certificate of Notification, File No. 70-8443, as Exhibit
                  C, in Form 8-K dated May 17, 1995, File No. 1-6468, as Exhibit
                  4 and in GEORGIA's Form 10-K for the year ended December 31,
                  1995, File No. 1-6468, as Exhibits 4(c)2, 4(c)3, 4(c)4, 4(c)5
                  and 4(c)6.)

        *(c)  2 - Satisfaction and Discharge of Indenture, Release and
                  Deed of Reconveyance dated as of February 27, 2002, by
                  JPMorgan Chase Bank, as Trustee, to GEORGIA relating to the
                  defeasance of the Indenture dated as of March 1, 1941 between
                  GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan
                  Bank), as Trustee, and indentures supplemental thereto through
                  October 15, 1995.

         (c)  3 - Subordinated Note Indenture dated as of August 1, 1996,
                  between GEORGIA and JPMorgan Chase Bank (formerly The Chase
                  Manhattan Bank), as Trustee, and indentures supplemental
                  thereto through January 1, 1997. (Designated in Form 8-K dated
                  August 21, 1996, File No. 1-6468, as Exhibits 4.1 and 4.2 and
                  in Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit
                  4.2.)



                                      E-6
<PAGE>



         (c)  4 - Subordinated Note Indenture dated as of June 1, 1997,
                  between GEORGIA and JPMorgan Chase Bank (formerly The Chase
                  Manhattan Bank), as Trustee, and indentures supplemental
                  thereto through February 25, 1999. (Designated in Certificate
                  of Notification, File No. 70-8461, as Exhibits D and E and
                  Form 8-K dated February 17, 1999, File No. 1-6468, as Exhibit
                  4.4.)

         (c)  5 - Senior Note Indenture dated as of January 1, 1998, between
                  GEORGIA and JPMorgan Chase Bank (formerly The Chase Manhattan
                  Bank), as Trustee, and indentures supplemental thereto through
                  May 8, 2001. (Designated in Form 8-K dated January 21, 1998,
                  File No. 1-6468, as Exhibits 4.1 and 4.2, in Forms 8-K each
                  dated November 19, 1998, File No. 1-6468, as Exhibit 4.2, in
                  Form 8-K dated March 3, 1999, File No. 1-6469 as Exhibit 4.2,
                  in Form 8-K dated February 15, 2000, File No. 1-6469 as
                  Exhibit 4.2, in Form 8-K dated January 26, 2001, File No.
                  1-6469 as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated
                  February 16, 2001, File No. 1-6469 as Exhibit 4.2 and in Form
                  8-K dated May 1, 2001, File No. 1-6468, as Exhibit 4.2.)

         (c)  6 - Amended and Restated Trust Agreement of Georgia Power
                  Capital Trust I dated as of August 1, 1996. (Designated in
                  Form 8-K dated August 21, 1996, File No. 1-6468, as Exhibit
                  4.5.)

         (c)  7 - Amended and Restated Trust Agreement of Georgia Power
                  Capital Trust II dated as of January 1, 1997. (Designated in
                  Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit
                  4.5.)

         (c)  8 - Amended and Restated Trust Agreement of Georgia Power
                  Capital Trust III dated as of June 1, 1997. (Designated in
                  Certificate of Notification, File No. 70-8461, as Exhibit C.)

         (c)  9 - Amended and Restated Trust Agreement of Georgia Power
                  Capital Trust IV dated as of February 1, 1999. (Designated in
                  Form 8-K dated February 17, 1999, as Exhibit 4.7-A)

         (c) 10 - Guarantee Agreement relating to Georgia Power Capital
                  Trust I dated as of August 1, 1996. (Designated in Form 8-K
                  dated August 21, 1996, File No. 1-6468, as Exhibit 4.8.)

         (c) 11 - Guarantee Agreement relating to Georgia Power Capital
                  Trust II dated as of January 1, 1997. (Designated in Form 8-K
                  dated January 9, 1997, File No. 1-6468, as Exhibit 4.8.)

         (c) 12 - Guarantee Agreement relating to Georgia Power Capital
                  Trust III dated as of June 1, 1997. (Designated in Certificate
                  of Notification, File No. 70-8461, as Exhibit F.)

         (c) 13 - Guarantee Agreement relating to Georgia Power Capital
                  Trust IV dated as of February 1, 1999. (Designated in Form 8-K
                  dated February 17, 1999, as Exhibit 4.11-A.)



                                      E-7
<PAGE>



      GULF

         (d)  1 - Indenture dated as of September 1, 1941, between GULF and
                  JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as
                  Trustee, and indentures supplemental thereto through November
                  1, 1996. (Designated in Registration Nos. 2-4833 as Exhibit
                  B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as Exhibit 2(a)-3,
                  2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2, 33-43739
                  as Exhibit 4(a)-2, in GULF's Form 10-K for the year ended
                  December 31, 1991, File No. 0-2429, as Exhibit 4(b), in Form
                  8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(a)-3,
                  in Registration No. 33-50165 as Exhibit 4(a)-2, in Form 8-K
                  dated July 12, 1993, File No. 0-2429, as Exhibit 4, in
                  Certificate of Notification, File No. 70-8229, as Exhibit A,
                  in Certificate of Notification, File No. 70-8229, as Exhibits
                  E and F, in Form 8-K dated January 17, 1996, File No. 0-2429,
                  as Exhibit 4, in Certificate of Notification, File No.
                  70-8229, as Exhibit A, in Certificate of Notification, File
                  No. 70-8229, as Exhibit A and in Form 8-K dated November 6,
                  1996, File No. 0-2429, as Exhibit 4.)

         (d)  2 - Subordinated Note Indenture dated as of January 1, 1997,
                  between GULF and JPMorgan Chase Bank (formerly The Chase
                  Manhattan Bank), as Trustee, and indentures supplemental
                  thereto through November 16, 2001. (Designated in Form 8-K
                  dated January 27, 1997, File No. 0-2429, as Exhibits 4.1 and
                  4.2, in Form 8-K dated July 28, 1997, File No. 0-2429, as
                  Exhibit 4.2, in Form 8-K dated January 13, 1998, File No.
                  0-2429, as Exhibit 4.2 and in Form 8-K dated November 8, 2001,
                  File No. 0-2429, as Exhibit 4.2.)

         (d)  3 - Senior Note Indenture dated as of January 1, 1998, between
                  GULF and JPMorgan Chase Bank (formerly The Chase Manhattan
                  Bank), as Trustee, and indentures supplemental thereto through
                  January 30, 2002. (Designated in Form 8-K dated June 17, 1998,
                  File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated
                  August 17, 1999, File No. 0-2429, as Exhibit 4.2, in Form 8-K
                  dated July 31, 2001, File No. 0-2429, as Exhibit 4.2, in Form
                  8-K dated October 5, 2001, File No. 0-2429, as Exhibit 4.2 and
                  in Form 8-K dated January 18, 2002, File No. 0-2429, as
                  Exhibit 4.2.)

         (d)  4 - Amended and Restated Trust Agreement of Gulf Power Capital
                  Trust I dated as of January 1, 1997. (Designated in Form 8-K
                  dated January 27, 1997, File No. 0-2429, as Exhibit 4.5.)

         (d)  5 - Amended and Restated Trust Agreement of Gulf Power Capital
                  Trust II dated as of January 1, 1998. (Designated in Form 8-K
                  dated January 13, 1998, File No. 0-2429, as Exhibit 4.5.)

         (d)  6 - Amended and Restated Trust Agreement of Gulf Power Capital
                  Trust III dated as of November 1, 2001. (Designated in Form
                  8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.5.)

         (d)  7 - Guarantee Agreement relating to Gulf Power Capital Trust I
                  dated as of January 1, 1997. (Designated in Form 8-K dated
                  January 27, 1997, File No. 0-2429, as Exhibit 4.8.)


                                      E-8
<PAGE>




         (d)  8 - Guarantee Agreement relating to Gulf Power Capital Trust
                  II dated as of January 1, 1998. (Designated in Form 8-K dated
                  January 13, 1998, File No. 0-2429, as Exhibit 4.8.)

         (d)  9 - Guarantee Agreement relating to Gulf Power Capital Trust
                  III dated as of November 1, 2001. (Designated in Form 8-K
                  dated November 8, 1998, File No. 0-2429, as Exhibit 4.8.)


         MISSISSIPPI

         (e)  1 - Indenture dated as of September 1, 1941, between
                  MISSISSIPPI and Bankers Trust Company, as Successor Trustee,
                  and indentures supplemental thereto through December 1, 1995.
                  (Designated in Registration Nos. 2-4834 as Exhibit B-3,
                  2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2, 2-71537
                  as Exhibit 4(a)-(2), 33-5414 as Exhibit 4(a)-(2), 33-39833 as
                  Exhibit 4(a)-2, in MISSISSIPPI's Form 10-K for the year ended
                  December 31, 1991, File No. 0-6849, as Exhibit 4(b), in Form
                  8-K dated August 5, 1992, File No. 0-6849, as Exhibit 4(a)-2,
                  in Second Certificate of Notification, File No. 70-7941, as
                  Exhibit I, in MISSISSIPPI's Form 8-K dated February 26, 1993,
                  File No. 0-6849, as Exhibit 4(a)-2, in Certificate of
                  Notification, File No. 70-8127, as Exhibit A, in Form 8-K
                  dated June 22, 1993, File No. 0-6849, as Exhibit 1, in
                  Certificate of Notification, File No. 70-8127, as Exhibit A,
                  in Form 8-K dated March 8, 1994, File No. 0-6849, as Exhibit
                  4, in Certificate of Notification, File No. 70-8127, as
                  Exhibit C and in Form 8-K dated December 5, 1995, File No.
                  0-6849, as Exhibit 4.)

         (e)  2 - Senior Note Indenture dated as of May 1, 1998 between
                  MISSISSIPPI and Bankers Trust Company, as Trustee and
                  indentures supplemental thereto through March 28, 2000.
                  (Designated in Form 8-K dated May 14, 1998, File No. 0-6849,
                  as Exhibits 4.1, 4.2(a) and 4.2(b) and in Form 8-K dated March
                  22, 2000, File No. 0-6849, as Exhibit 4.2.)

         (e)  3 - Subordinated Note Indenture dated as of February 1, 1997,
                  between MISSISSIPPI and Bankers Trust Company, as Trustee, and
                  indenture supplemental thereto dated as of February 1, 1997.
                  (Designated in Form 8-K dated February 20, 1997, File No.
                  0-6849, as Exhibits 4.1 and 4.2.)

         (e)  4 - Amended and Restated Trust Agreement of Mississippi Power
                  Capital Trust I dated as of February 1, 1997. (Designated in
                  Form 8-K dated February 20, 1997, File No. 0-6849, as Exhibit
                  4.5.)

         (e)  5 - Guarantee Agreement relating to Mississippi Power Capital
                  Trust I dated as of February 1, 1997. (Designated in Form 8-K
                  dated February 20, 1997, File No. 0-6849, as Exhibit 4.8.)


         SAVANNAH

         (f)  1 - Indenture dated as of March 1, 1945, between SAVANNAH and
                  The Bank of New York, as Trustee, and indentures supplemental
                  thereto through May 1, 1996. (Designated in Registration Nos.
                  33-25183 as Exhibit 4(a)-(1), 33-41496 as Exhibit 4(a)-(2),
                  33-45757 as Exhibit 4(a)-(2), in SAVANNAH's Form 10-K for



                                      E-9
<PAGE>


                  the year ended December 31, 1991, File No. 1-5072, as Exhibit
                  4(b), in Form 8-K dated July 8, 1992, File No. 1-5072, as
                  Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit
                  4(a)-(2), in Form 8-K dated July 22, 1993, File No. 1-5072, as
                  Exhibit 4, in Form 8-K dated May 18, 1995, File No. 1-5072, as
                  Exhibit 4 and in Form 8-K dated May 23, 1996, File No. 1-5072,
                  as Exhibit 4.)

         (f)  2 - Senior Note Indenture dated as of March 1, 1998 between
                  SAVANNAH and The Bank of New York, as Trustee and indentures
                  supplemental thereto through May 17, 2001. (Designated in Form
                  8-K dated March 9, 1998, File No. 1-5072, as Exhibits 4.1 and
                  4.2 and in Form 8-K dated May 8, 2001, File No. 1-5072, as
                  Exhibits 4.2(a) and 4.2(b).)

         (f)  3 - Subordinated Note Indenture dated as of December 1, 1998,
                  between SAVANNAH and The Bank of New York, as Trustee, and
                  indenture supplemental thereto dated as of December 9, 1998.
                  (Designated in Form 8-K dated December 3, 1998, File No.
                  1-5072, as Exhibit 4.3 and 4.4.)

         (f)  4 - Amended and Restated Trust Agreement of Savannah Electric
                  Capital Trust I dated as of December 1, 1998. (Designated in
                  Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit
                  4.7.)

         (f)  5 - Guarantee Agreement relating to Savannah Electric Capital
                  Trust I dated as of December 1, 1998. (Designated in Form 8-K
                  dated December 3, 1998, File No. 1-5072, as Exhibit 4.11.)


(10)     Material Contracts

         SOUTHERN

         (a)  1 - Service contracts dated as of January 1, 1984, between SCS
                  and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
                  and Amendment No. 1 dated as of September 6, 1985 between SCS
                  and SOUTHERN. (Designated in SOUTHERN's Form 10-K for the year
                  ended December 31, 1984, File No. 1-3526, as Exhibit 10(a) and
                  in SOUTHERN's Form 10-K for the year ended December 31, 1985,
                  File No. 1-3526, as Exhibit 10(a)(3).)

        *(a)  2 - Service contract dated as of January 1, 2001, between
                  SCS and Southern Power.

         (a)  3 - Service contract dated as of March 3, 1988, between SCS
                  and SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year
                  ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.)

         (a)  4 - Service contract dated as of January 15, 1991, between SCS
                  and Southern Nuclear. (Designated in SOUTHERN's Form 10-K for
                  the year ended December 31, 1991, File No. 1-3526, as Exhibit
                  10(a)(4).)

         (a)  5 - Service contract dated as of December 12, 1994, between
                  SCS and Mobile Energy Services Company, Inc. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 1994,
                  File No. 1-3526, as Exhibit 10(a)58.)


                                      E-10
<PAGE>




         (a)  6 - Interchange contract dated February 17, 2000, between
                  ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
                  (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 2000, File No. 1-3526, as Exhibit 10(a)6.)

         (a)  7 - Agreement dated as of January 27, 1959, Amendment No. 1
                  dated as of October 27, 1982 and Amendment No. 2 dated
                  November 4, 1993 and effective June 1, 1994, among SEGCO,
                  ALABAMA and GEORGIA. (Designated in Registration No. 2-59634
                  as Exhibit 5(c), in GEORGIA's Form 10-K for the year ended
                  December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2) and in
                  ALABAMA's Form 10-K for the year ended December 31, 1994, File
                  No. 1-3164, as Exhibit 10(b)18.)

         (a)  8 - Joint Committee Agreement dated as of August 27, 1976,
                  among GEORGIA, OPC, MEAG and Dalton. (Designated in
                  Registration No. 2-61116 as Exhibit 5(d).)

         (a)  9 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
                  Participation Agreement dated as of January 6, 1975, between
                  GEORGIA and OPC. (Designated in Form 8-K for January, 1975,
                  File No. 1-6468, as Exhibit (b)(1).)

         (a) 10 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
                  of January 6, 1975, between GEORGIA and OPC. (Designated in
                  Form 8-K for January, 1975, File No. 1-6468, as Exhibit
                  (b)(3).)

         (a) 11 - Revised and Restated Integrated Transmission System
                  Agreement dated as of November 12, 1990, between GEORGIA and
                  OPC. (Designated in GEORGIA's Form 10-K for the year ended
                  December 31, 1990, File No. 1-6468, as Exhibit 10(g).)

         (a) 12 - Plant Hal Wansley Purchase and Ownership Participation
                  Agreement dated as of March 26, 1976, between GEORGIA and OPC.
                  (Designated in Certificate of Notification, File No. 70-5592,
                  as Exhibit A.)

         (a) 13 - Plant Hal Wansley Operating Agreement dated as of March
                  26, 1976, between GEORGIA and OPC. (Designated in Certificate
                  of Notification, File No. 70-5592, as Exhibit B.)

         (a) 14 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
                  Participation Agreement dated as of August 27, 1976, between
                  GEORGIA, MEAG and Dalton. (Designated in Form 8-K dated as of
                  June 13, 1977, File No. 1-6468, as Exhibit (b)(1).)

         (a) 15 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
                  of August 27, 1976, between GEORGIA, MEAG and Dalton.
                  (Designated in Form 8-K for February 1977, File No. 1-6468, as
                  Exhibit (b)(2).)

         (a) 16 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
                  and Ownership Participation Agreement dated as of August 27,
                  1976 and Amendment No. 1 dated as of January 18, 1977, among
                  GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File
                  No. 70-5792, as Exhibit B-1 and in Form 8-K for January 1977,
                  File No. 1-6468, as Exhibit (B)(3).)



                                      E-11
<PAGE>



         (a) 17 - Alvin W. Vogtle Nuclear Units Number One and Two
                  Operating Agreement dated as of August 27, 1976, among
                  GEORGIA, OPC, MEAG and Dalton. (Designated in Form U-1, File
                  No. 70-5792, as Exhibit B-2.)

         (a) 18 - Alvin W. Vogtle Nuclear Units Number One and Two
                  Purchase, Amendment, Assignment and Assumption Agreement dated
                  as of November 16, 1983, between GEORGIA and MEAG. (Designated
                  in GEORGIA's Form 10-K for the year ended December 31, 1983,
                  File No. 1-6468, as Exhibit 10(k)(4).)

         (a) 19 - Plant Hal Wansley Purchase and Ownership Participation
                  Agreement dated as of August 27, 1976, between GEORGIA and
                  MEAG. (Designated in Form 8-K dated as of July 5, 1977, File
                  No. 1-6468, as Exhibit (b)(2).)

         (a) 20 - Plant Hal Wansley Operating Agreement dated as of August
                  27, 1976, between GEORGIA and MEAG. (Designated in Form 8-K
                  dated as of July 5, 1977, File No. 1-6468, as Exhibit (b)(4).)

         (a) 21 - Nuclear Operating Agreement between Southern Nuclear and
                  GEORGIA dated as of July 1, 1993. (Designated in SOUTHERN's
                  Form 10-K for the year ended December 31, 1997, File No.
                  1-3526, as Exhibit 10(a)21.)

         (a) 22 - Pseudo Scheduling and Services Agreement between GEORGIA
                  and MEAG dated as of April 8, 1997. (Designated in SOUTHERN's
                  Form 10-K for the year ended December 31, 1997, File No.
                  1-3526, as Exhibit 10(a)22.)

         (a) 23 - Plant Hal Wansley Purchase and Ownership Participation
                  Agreement dated as of April 19, 1977, between GEORGIA and
                  Dalton. (Designated in Form 8-K dated as of June 13, 1977,
                  File No. 1-6468, as Exhibit (b)(3).)

         (a) 24 - Plant Hal Wansley Operating Agreement dated as of April
                  19, 1977, between GEORGIA and Dalton. (Designated in Form 8-K
                  dated as of June 13, 1977, File No. 1-6468, as Exhibit
                  (b)(7).)

         (a) 25 - Plant Robert W. Scherer Units Number One and Two Purchase
                  and Ownership Participation Agreement dated as of May 15,
                  1980, Amendment No. 1 dated as of December 30, 1985, Amendment
                  No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of
                  August 1, 1988 and Amendment No. 4 dated as of December 31,
                  1990, among GEORGIA, OPC, MEAG and Dalton. (Designated in Form
                  U-1, File No. 70-6481, as Exhibit B-3, in SOUTHERN's Form 10-K
                  for the year ended December 31, 1987, File No. 1-3526, as
                  Exhibit 10(o)(2), in SOUTHERN's Form 10-K for the year ended
                  December 31, 1989, File No. 1-3526, as Exhibit 10(n)(2) and in
                  SOUTHERN's Form 10-K for the year ended December 31, 1993,
                  File No. 1-3526, as Exhibit 10(a)54.)

         (a) 26 - Plant Robert W. Scherer Units Number One and Two
                  Operating Agreement dated as of May 15, 1980, Amendment No. 1
                  dated as of December 3, 1985 and Amendment No. 2 dated as of
                  December 31, 1990, among GEORGIA, OPC, MEAG and Dalton.
                  (Designated in Form U-1, File No. 70-6481, as Exhibit B-4, in
                  SOUTHERN's Form 10-K for the year ended December 31, 1987,
                  File No. 1-3526, as Exhibit 10(o)(4) and in SOUTHERN's Form
                  10-K for the year ended December 31, 1993, File No. 1-3526, as
                  Exhibit 10(a)55.)



                                      E-12
<PAGE>




         (a) 27 - Plant Robert W. Scherer Purchase, Sale and Option
                  Agreement dated as of May 15, 1980, between GEORGIA and MEAG.
                  (Designated in Form U-1, File No. 70-6481, as Exhibit B-1.)

         (a) 28 - Plant Robert W. Scherer Purchase and Sale Agreement dated
                  as of May 16, 1980, between GEORGIA and Dalton. (Designated in
                  Form U-1, File No. 70-6481, as Exhibit B-2.)

         (a) 29 - Plant Robert W. Scherer Unit Number Three Purchase and
                  Ownership Participation Agreement dated as of March 1, 1984,
                  Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
                  dated as of August 1, 1988, between GEORGIA and GULF.
                  (Designated in Form U-1, File No. 70-6573, as Exhibit B-4, in
                  SOUTHERN's Form 10-K for the year ended December 31, 1987, as
                  Exhibit 10(o)(2) and in SOUTHERN's Form 10-K for the year
                  ended December 31, 1989, as Exhibit 10(n)(2).)

         (a) 30 - Plant Robert W. Scherer Unit Number Three Operating
                  Agreement dated as of March 1, 1984, between GEORGIA and GULF.
                  (Designated in Form U-1, File No. 70-6573, as Exhibit B-5.)

         (a) 31 - Plant Robert W. Scherer Unit No. Four Amended and
                  Restated Purchase and Ownership Participation Agreement by and
                  among GEORGIA, FP&L and JEA, dated as of December 31, 1990 and
                  Amendment No. 1 dated as of June 15, 1994. (Designated in Form
                  U-1, File No. 70-7843, as Exhibit B-1 and in SOUTHERN's Form
                  10-K for the year ended December 31, 1994, File No. 1-3526, as
                  Exhibit 10(a)60.)

         (a) 32 - Plant Robert W. Scherer Unit No. Four Operating Agreement
                  by and among GEORGIA, FP&L and JEA, dated as of December 31,
                  1990 and Amendment No. 1 dated as of June 15, 1994.
                  (Designated in Form U-1, File No. 70-7843, as Exhibit B-2 and
                  in SOUTHERN's Form 10-K for the year ended December 31, 1994,
                  File No. 1-3526, as Exhibit 10(a)61.)

         (a) 33 - Unit Power Sales Agreement dated July 19, 1988, between
                  FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
                  (Designated in SAVANNAH's Form 10-K for the year ended
                  December 31, 1988, File No. 1-5072, as Exhibit 10(d).)

         (a) 34 - Amended Unit Power Sales Agreement dated July 20, 1988,
                  between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. (Designated in SAVANNAH's Form 10-K for the year
                  ended December 31, 1988, File No. 1-5072, as Exhibit 10(e).)

         (a) 35 - Amended Unit Power Sales Agreement dated August 17, 1988,
                  between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. (Designated in SAVANNAH's Form 10-K for the year
                  ended December 31, 1988, File No. 1-5072, as Exhibit 10(f).)

         (a) 36 - Rocky Mountain Pumped Storage Hydroelectric Project
                  Ownership Participation Agreement dated November 18, 1988,
                  between OPC and GEORGIA. (Designated in GEORGIA's Form 10-K
                  for the year ended December 31, 1988, File No. 1-6468, as
                  Exhibit 10(x).)



                                      E-13
<PAGE>


         (a) 37 - Rocky Mountain Pumped Storage Hydroelectric Project
                  Operating Agreement dated November 18, 1988, between OPC and
                  GEORGIA. (Designated in GEORGIA's Form 10-K for the year ended
                  December 31, 1988, File No. 1-6468, as Exhibit 10(y).)

         (a) 38 - Purchase and Ownership Agreement for Joint Ownership
                  Interest in the James H. Miller, Jr. Steam Electric Generating
                  Plant Units One and Two dated November 18, 1988, between
                  ALABAMA and AEC. (Designated in Form U-1, File No. 70-7609, as
                  Exhibit B-1.)

         (a) 39 - Operating Agreement for Joint Ownership Interest in the
                  James H. Miller, Jr. Steam Electric Generating Plant Units One
                  and Two dated November 18, 1988, between ALABAMA and AEC.
                  (Designated in Form U-1, File No. 70-7609, as Exhibit B-2.)

         (a) 40 - Transmission Facilities Agreement dated February 25,
                  1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2
                  dated December 6, 1983, between Gulf States and MISSISSIPPI.
                  (Designated in MISSISSIPPI's Form 10-K for the year ended
                  December 31, 1981, File No. 0-6849, as Exhibit 10(f), in
                  MISSISSIPPI's Form 10-K for the year ended December 31, 1982,
                  File No. 0-6849, as Exhibit 10(f)(2) and in MISSISSIPPI's Form
                  10-K for the year ended December 31, 1983, File No. 0-6849, as
                  Exhibit 10(f)(3).)

         (a) 41 - Long Term Transaction Service Agreement between GEORGIA
                  and OPC dated as of February 26, 1999. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 1999,
                  File No. 1-3526, as Exhibit 10(a)46.)

         (a) 42 - Revised and Restated Coordination Services Agreement
                  between and among GEORGIA, OPC and Georgia Systems Operations
                  Corporation dated as of September 10, 1997. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 1997,
                  File No. 1-3526, as Exhibit 10(a)48.)

         (a) 43 - Amended and Restated Nuclear Managing Board Agreement for
                  Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and
                  Dalton dated as of July 1, 1993. (Designated in SOUTHERN's
                  Form 10-K for the year ended December 31, 1993, File No.
                  1-3526, as Exhibit 10(a)49.)

         (a) 44 - Integrated Transmission System Agreement, Power Sale and
                  Coordination Umbrella Agreement between GEORGIA and OPC dated
                  as of November 12, 1990. (Designated in GEORGIA's Form 10-K
                  for the year ended December 31, 1990, File No. 1-6468, as
                  Exhibit 10(ff).)

         (a) 45 - Revised and Restated Integrated Transmission System
                  Agreement between GEORGIA and Dalton dated as of December 7,
                  1990. (Designated in GEORGIA's Form 10-K for the year ended
                  December 31, 1990, File No. 1-6468, as Exhibit 10(gg).)

         (a) 46 - Revised and Restated Integrated Transmission System
                  Agreement between GEORGIA and MEAG dated as of December 7,
                  1990. (Designated in GEORGIA's Form 10-K for the year ended
                  December 31, 1990, File No. 1-6468, as Exhibit 10(hh).)



                                      E-14
<PAGE>



         (a) 47 - Long Term Transmission Service Agreement between Entergy
                  Power, Inc. and ALABAMA, MISSISSIPPI and SCS. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 1992,
                  File No. 1-3526, as Exhibit 10(a)53.)

         (a) 48 - Plant Scherer Managing Board Agreement dated as of
                  December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L
                  and JEA. (Designated in SOUTHERN's Form 10-K for the year
                  ended December 31, 1993, File No. 1-3526, as Exhibit 10(a)56.)

         (a) 49 - Plant McIntosh Combustion Turbine Purchase and Ownership
                  Participation Agreement between GEORGIA and SAVANNAH dated as
                  of December 15, 1992. (Designated in SOUTHERN's Form 10-K for
                  the year ended December 31, 1993, File No. 1-3526, as Exhibit
                  10(a)57.)

         (a) 50 - Plant McIntosh Combustion Turbine Operating Agreement
                  between GEORGIA and SAVANNAH dated as of December 15, 1992.
                  (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 1993, File No. 1-3526, as Exhibit 10(a)58.)

         (a) 51 - Operating Agreement for the Joseph M. Farley Nuclear
                  Plant between ALABAMA and Southern Nuclear dated as of
                  December 23, 1991. (Designated in Form U-1, File No. 70-7530,
                  as Exhibit B-7.)

        *(a) 52 - The Southern Company Employee Savings Plan, Amended
                  and Restated effective January 1, 2002.

        *(a) 53 - The Southern Company Employee Stock Ownership Plan,
                  Amended and Restated effective January 1, 2002.

       # (a) 54 - Southern Company Omnibus Incentive Compensation Plan,
                  Amended and Restated effective May 23, 2001. (Designated in
                  Form S-8, File No. 333-73462, as Exhibit 4(c).)

       # (a) 55 - The Deferred Compensation Plan for the Directors of
                  The Southern Company, Amended and Restated effective February
                  19, 2001. (Designated in SOUTHERN's Form 10-K for the year
                  ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)59.)

       # (a) 56 - The Southern Company Outside Directors Pension Plan.
                  (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 1994, File No. 1-3526, as Exhibit 10(a)77.)

       # (a) 57 - The Southern Company Deferred Compensation Plan,
                  Amended and Restated effective February 23, 2001. (Designated
                  in SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)61.)

       # (a) 58 - The Southern Company Outside Directors Stock Plan and
                  First Amendment thereto. (Designated in Registration No.
                  33-54415 as Exhibit 4(c) and in SOUTHERN's Form 10-K for the
                  year ended December 31, 1995, File No. 1-3526, as Exhibit
                  10(a)79.)



                                      E-15
<PAGE>


       # (a) 59 - Outside Directors Stock Plan for Subsidiaries of The
                  Southern Company, Amended and Restated effective January 1,
                  2000. (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 2000, File No. 1-3526, as Exhibit 10(a)63.)

         (a) 60 - The Southern Company Pension Plan, effective as of
                  January 1, 1997 and all amendments thereto through Amendment
                  Number Six. (Designated in SOUTHERN's Form 10-K for the year
                  ended December 31, 1996, File No. 1-3526, as Exhibit 10(a)83,
                  in SOUTHERN's Form 10-K for the year ended December 31, 1997,
                  File No. 1-3526, as Exhibit 10(a)79, in SOUTHERN's Form 10-K
                  for the year ended December 31, 1998, File No. 1-3526 as
                  Exhibit 10(a)71, in SOUTHERN's Form 10-K for the year ended
                  December 31, 1999, File No. 1-3526, as Exhibit 10(a)72 and in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526 as Exhibit 10(a)66.)

        *(a) 61 - Amendment Number Seven to The Southern Company
                  Pension Plan.

       #*(a) 62 - The Southern Company Supplemental Executive
                  Retirement Plan, Amended and Restated effective May 1, 2000.

       #*(a) 63 - The Southern Company Performance Sharing Plan,
                  Amended and Restated effective January 1, 2002.

       #*(a) 64 - The Southern Company Supplemental Benefit Plan,
                  Amended and Restated effective May 1, 2000.

         (a) 65 - Southern Company Change in Control Severance Plan,
                  Amended and Restated effective July 10, 2000. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)72.)

       # (a) 66 - Southern Company Executive Change in Control
                  Severance Plan, Amended and Restated effective July 10, 2000.
                  (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 2000, File No. 1-3526, as Exhibit 10(a)73.)

       # (a) 67 - Deferred Compensation Agreement between SOUTHERN,
                  Southern Nuclear and William G. Hairston III. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 1998,
                  File No. 1-3526 as Exhibit 10(a)81.)

       # (a) 68 - Deferred Compensation Agreement between SOUTHERN,
                  GEORGIA and Warren Y. Jobe. (Designated in SOUTHERN's Form
                  10-K for the year ended December 31, 1998, File No. 1-3526 as
                  Exhibit 10(a)82.)

       # (a) 69 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, GULF and Travis J. Bowden. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)79.)

       # (a) 70 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SCS and A. W. Dahlberg. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)80.)



                                      E-16
<PAGE>


       # (a) 71 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, MISSISSIPPI and Dwight H. Evans. (Designated
                  in SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)81.)

       # (a) 72 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SCS and Henry Allen Franklin. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)83.)

       # (a) 73 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, Southern Nuclear and William G. Hairston,
                  III. (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 2000, File No. 1-3526, as Exhibit 10(a)84.)

       # (a) 74 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, ALABAMA and Elmer B. Harris. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)85.)

       # (a) 75 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SAVANNAH and G. Edison Holland, Jr.
                  (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 2000, File No. 1-3526, as Exhibit 10(a)86.)

       # (a) 76 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SCS and C. Alan Martin. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)87.)

       # (a) 77 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SCS and Charles Douglas McCrary. (Designated
                  in SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)88.)

       # (a) 78 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, GEORGIA and David M. Ratcliffe. (Designated
                  in SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)89.)

       # (a) 79 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SCS and Stephen A. Wakefield. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)90.)

       # (a) 80 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SCS and W. Lawrence Westbrook. (Designated
                  in SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)91.)

       # (a) 81 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SCS and Gale E. Klappa. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)92.)

       # (a) 82 - Deferred Compensation Agreement between SOUTHERN and
                  William L. Westbrook. (Designated in SOUTHERN's Form 10-K for
                  the year ended December 31, 2000, File No. 1-3526, as Exhibit
                  10(a)94.)

       #*(a) 83 - First Amendment to Deferred Compensation Agreement
                  between SOUTHERN and William L. Westbrook dated September 7,
                  2001.



                                      E-17
<PAGE>


       # (a) 84 - Deferred Compensation Agreement between SOUTHERN and
                  Alfred W. Dahlberg, III. (Designated in SOUTHERN's Form 10-K
                  for the year ended December 31, 2000, File No. 1-3526, as
                  Exhibit 10(a)95.)

       # (a) 85 - Southern Company Change in Control Benefit Plan
                  Determination Policy, effective July 10, 2000. (Designated in
                  SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)96.)

       # (a) 86 - Change in Control Agreement between SOUTHERN, SCS and
                  Robert H. Haubein, Jr. (Designated in SOUTHERN's Form 10-K for
                  the year ended December 31, 2000, File No. 1-3526, as Exhibit
                  10(a)97.)

       # (a) 87 - Master Separation and Distribution Agreement dated as
                  of September 1, 2000 between SOUTHERN and Mirant. (Designated
                  in SOUTHERN's Form 10-K for the year ended December 31, 2000,
                  File No. 1-3526, as Exhibit 10(a)100.)

       # (a) 88 - Indemnification and Insurance Matters Agreement dated
                  as of September 1, 2000 between SOUTHERN and Mirant.
                  (Designated in SOUTHERN's Form 10-K for the year ended
                  December 31, 2000, File No. 1-3526, as Exhibit 10(a)101.)

       # (a) 89 - Tax Indemnification Agreement dated as of September
                  1, 2000 among SOUTHERN and its affiliated companies and Mirant
                  and its affiliated companies. (Designated in SOUTHERN's Form
                  10-K for the year ended December 31, 2000, File No. 1-3526, as
                  Exhibit 10(a)102.)

       # (a) 90 - Southern Company Deferred Compensation Trust
                  Agreement dated as of January 1, 2001 between Wachovia Bank,
                  N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                  SAVANNAH, Southern Communications, Energy Solutions, Mirant
                  and Southern Nuclear. (Designated in SOUTHERN's Form 10-K for
                  the year ended December 31, 2000, File No. 1-3526, as Exhibit
                  10(a)103.)

       # (a) 91 - Deferred Stock Trust Agreement for Directors of
                  SOUTHERN and its subsidiaries, dated as of January 1, 2000,
                  between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
                  GULF, MISSISSIPPI and SAVANNAH. (Designated in SOUTHERN's Form
                  10-K for the year ended December 31, 2000, File No. 1-3526, as
                  Exhibit 10(a)104.)

       #*(a) 92 - Amended and Restated Deferred Cash Compensation
                  Trust Agreement for Directors of SOUTHERN and its
                  subsidiaries, effective September 1, 2001, between Wachovia
                  Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
                  SAVANNAH.


         ALABAMA

         (b)  1 - Service contracts dated as of January 1, 1984, between SCS
                  and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
                  and Amendment No. 1 dated as of September 6, 1985 between SCS
                  and SOUTHERN. See Exhibit 10(a)1 herein.



                                      E-18
<PAGE>


         (b)  2 - Interchange contract dated February 17, 2000, between
                  ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
                  See Exhibit 10(a)6 herein.

         (b)  3 - Agreement dated as of January 27, 1959, Amendment No. 1
                  dated as of October 27, 1982 and Amendment No. 2 dated
                  November 4, 1993 and effective June 1, 1994, among SEGCO,
                  ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.

         (b)  4 - Unit Power Sales Agreement dated July 19, 1988, between
                  FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
                  See Exhibit 10(a)33 herein.

         (b)  5 - Amended Unit Power Sales Agreement dated July 20, 1988,
                  between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)34 herein.

         (b)  6 - Amended Unit Power Sales Agreement dated August 17, 1988,
                  between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)35 herein.

         (b)  7 - Firm Power Purchase Contract between ALABAMA and AMEA.
                  (Designated in Certificate of Notification, File No. 70-7212,
                  as Exhibit B.)

         (b)  8 - 1991 Firm Power Purchase Contract between ALABAMA and
                  AMEA. (Designated in Form U-1, File No. 70-7873, as Exhibit
                  B-1.)

         (b)  9 - Purchase and Ownership Agreement for Joint Ownership
                  Interest in the James H. Miller, Jr. Steam Electric Generating
                  Plant Units One and Two dated November 18, 1988, between
                  ALABAMA and AEC. See Exhibit 10(a)38 herein.

         (b) 10 - Operating Agreement for Joint Ownership Interest in the
                  James H. Miller, Jr. Steam Electric Generating Plant Units One
                  and Two dated November 18, 1988, between ALABAMA and AEC. See
                  Exhibit 10(a)39 herein.

         (b) 11 - Long Term Transmission Service Agreement between Entergy
                  Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit
                  10(a)47 herein.

         (b) 12 - Operating Agreement for the Joseph M. Farley Nuclear
                  Plant between ALABAMA and Southern Nuclear dated as of
                  December 23, 1991. See Exhibit 10(a)51 herein.

        *(b) 13 - The Southern Company Employee Savings Plan, Amended
                  and Restated effective January 1, 2002. See Exhibit 10(a)52
                  herein.

        *(b) 14 - The Southern Company Employee Stock Ownership Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)53 herein.

       # (b) 15 - Southern Company Omnibus Incentive Compensation Plan,
                  Amended and Restated effective May 23, 2001. See Exhibit
                  10(a)54 herein.

       # (b) 16 - The Southern Company Deferred Compensation Plan,
                  Amended and Restated effective February 23, 2001. See Exhibit
                  10(a)57 herein.



                                      E-19
<PAGE>


       # (b) 17 - The Southern Company Outside Directors Pension Plan.
                  See Exhibit 10(a)56 herein.

       # (b) 18 - Outside Directors Stock Plan for Subsidiaries of The
                  Southern Company, Amended and Restated effective January 1,
                  2000. See Exhibit 10(a)59 herein.

         (b) 19 - The Southern Company Pension Plan, effective as of
                  January 1, 1997 and all amendments thereto through Amendment
                  Number Six. See Exhibit 10(a)60 herein.

        *(b) 20 - Amendment Number Seven to The Southern Company
                  Pension Plan. See Exhibit 10(a)61 herein.

       #*(b) 21 - The Southern Company Supplemental Executive Retirement
                  Plan, Amended and Restated effective May 1, 2000. See Exhibit
                  10(a)62 herein.

       #*(b) 22 - The Southern Company Performance Sharing Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)63 herein.

       #*(b) 23 - The Southern Company Supplemental Benefit Plan,
                  Amended and Restated effective May 1, 2000. See Exhibit
                  10(a)64 herein.

         (b) 24 - Southern Company Change in Control Severance Plan,
                  Amended and Restated effective July 10, 2000. See Exhibit
                  10(a)65 herein.

       # (b) 25 - Southern Company Executive Change in Control
                  Severance Plan, Amended and Restated effective July 10, 2000.
                  See Exhibit 10(a)66 herein.

       #*(b) 26 - Deferred Compensation Agreement between ALABAMA and
                  Elmer B. Harris.

       # (b) 27 - Supplemental Pension Agreement between ALABAMA, GULF
                  and Travis J. Bowden. (Designated in ALABAMA's Form 10-K for
                  the year ended December 31, 1998, File No. 1-3164, as Exhibit
                  10(b)40.)

       #*(b) 28 - Deferred Compensation Plan for Directors of Alabama
                  Power Company, Amended and Restated effective January 1, 2001.

       # (b) 29 - Southern Company Change in Control Benefit Plan
                  Determination Policy, effective July 10, 2000. See Exhibit
                  10(a)85 herein.

       # (b) 30 - Southern Company Deferred Compensation Trust
                  Agreement dated as of January 1, 2001 between Wachovia Bank,
                  N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                  SAVANNAH, Southern Communications, Energy Solutions, Mirant
                  and Southern Nuclear. See Exhibit 10(a)90 herein.

       # (b) 31 - Deferred Stock Trust Agreement for Directors of
                  SOUTHERN and its subsidiaries, dated as of January 1, 2000,
                  between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
                  GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(b)91 herein.



                                      E-20
<PAGE>


       #*(b) 32 - Amended and Restated Deferred Cash Compensation
                  Trust Agreement for Directors of SOUTHERN and its
                  subsidiaries, dated as of September 1, 2001, between Wachovia
                  Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
                  SAVANNAH. See Exhibit 10(a)92 herein.


         GEORGIA

         (c)  1 - Service contracts dated as of January 1, 1984, between SCS
                  and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
                  and Amendment No. 1 dated as of September 6, 1985, between SCS
                  and SOUTHERN. See Exhibit 10(a)1 herein.

         (c)  2 - Interchange contract dated February 17, 2000, between
                  ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
                  See Exhibit 10(a)6 herein.

         (c)  3 - Agreement dated as of January 27, 1959, Amendment No. 1
                  dated as of October 27, 1982 and Amendment No. 2 dated
                  November 4, 1993 and effective June 1, 1994, among SEGCO,
                  ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.

         (c)  4 - Joint Committee Agreement dated as of August 27, 1976,
                  among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)8
                  herein.

         (c)  5 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
                  Participation Agreement dated as of January 6, 1975, between
                  GEORGIA and OPC. See Exhibit 10(a)9 herein.

         (c)  6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
                  of January 6, 1975, between GEORGIA and OPC. See Exhibit
                  10(a)10 herein.

         (c)  7 - Revised and Restated Integrated Transmission System
                  Agreement dated as of November 12, 1990, between GEORGIA and
                  OPC. See Exhibit 10(a)11 herein.

         (c)  8 - Plant Hal Wansley Purchase and Ownership Participation
                  Agreement dated as of March 26, 1976, between GEORGIA and OPC.
                  See Exhibit 10(a)12 herein.

         (c)  9 - Plant Hal Wansley Operating Agreement dated as of March
                  26, 1976, between GEORGIA and OPC. See Exhibit 10(a)13 herein.

         (c) 10 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
                  Participation Agreement dated as of August 27, 1976, between
                  GEORGIA, MEAG and Dalton. See Exhibit 10(a)14 herein.

         (c) 11 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
                  of August 27, 1976, between GEORGIA, MEAG and Dalton. See
                  Exhibit 10(a)15 herein.

         (c) 12 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
                  and Ownership Participation Agreement dated as of August 27,
                  1976 and Amendment No. 1 dated as of January 18, 1977, among
                  GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)16 herein.



                                      E-21
<PAGE>


         (c) 13 - Alvin W. Vogtle Nuclear Units Number One and Two
                  Operating Agreement dated as of August 27, 1976, among
                  GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)17 herein.

         (c) 14 - Alvin W. Vogtle Nuclear Units Number One and Two
                  Purchase, Amendment, Assignment and Assumption Agreement dated
                  as of November 16, 1983, between GEORGIA and MEAG. See Exhibit
                  10(a)18 herein.

         (c) 15 - Plant Hal Wansley Purchase and Ownership Participation
                  Agreement dated as of August 27, 1976, between GEORGIA and
                  MEAG. See Exhibit 10(a)19 herein.

         (c) 16 - Plant Hal Wansley Operating Agreement dated as of August
                  27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)20
                  herein.

         (c) 17 - Nuclear Operating Agreement between Southern Nuclear and
                  GEORGIA dated as of July 1, 1993. See Exhibit 10(a)21 herein.

         (c) 18 - Pseudo Scheduling and Services Agreement between GEORGIA
                  and MEAG dated as of April 8, 1997. See Exhibit 10(a)22
                  herein.

         (c) 19 - Plant Hal Wansley Purchase and Ownership Participation
                  Agreement dated as of April 19, 1977, between GEORGIA and
                  Dalton. See Exhibit 10(a)23 herein.

         (c) 20 - Plant Hal Wansley Operating Agreement dated as of April
                  19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)24
                  herein.

         (c) 21 - Plant Robert W. Scherer Units Number One and Two Purchase
                  and Ownership Participation Agreement dated as of May 15,
                  1980, Amendment No. 1 dated as of December 30, 1985, Amendment
                  No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of
                  August 1, 1988 and Amendment No. 4 dated as of December 31,
                  1990, among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)25
                  herein.

         (c) 22 - Plant Robert W. Scherer Units Number One and Two
                  Operating Agreement dated as of May 15, 1980, Amendment No. 1
                  dated as of December 3, 1985 and Amendment No. 2 dated as of
                  December 31, 1990, among GEORGIA, OPC, MEAG and Dalton. See
                  Exhibit 10(a)26 herein.

         (c) 23 - Plant Robert W. Scherer Purchase, Sale and Option
                  Agreement dated as of May 15, 1980, between GEORGIA and MEAG.
                  See Exhibit 10(a)27 herein.

         (c) 24 - Plant Robert W. Scherer Purchase and Sale Agreement dated
                  as of May 16, 1980, between GEORGIA and Dalton. See Exhibit
                  10(a)28 herein.

         (c) 25 - Plant Robert W. Scherer Unit Number Three Purchase and
                  Ownership Participation Agreement dated as of March 1, 1984,
                  Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
                  dated as of August 1, 1988, between GEORGIA and GULF. See
                  Exhibit 10(a)29 herein.

         (c) 26 - Plant Robert W. Scherer Unit Number Three Operating
                  Agreement dated as of March 1, 1984, between GEORGIA and GULF.
                  See Exhibit 10(a)30 herein.



                                      E-22
<PAGE>


         (c) 27 - Plant Robert W. Scherer Unit No. Four Amended and
                  Restated Purchase and Ownership Participation Agreement by and
                  among GEORGIA, FP&L and JEA dated as of December 31, 1990 and
                  Amendment No. 1 dated as of June 15, 1994. See Exhibit 10(a)31
                  herein.

         (c) 28 - Plant Robert W. Scherer Unit No. Four Operating Agreement
                  by and among GEORGIA, FP&L and JEA dated as of December 31,
                  1990 and Amendment No. 1 dated as of June 15, 1994. See
                  Exhibit 10(a)32 herein.

         (c) 29 - Unit Power Sales Agreement dated July 19, 1988, between
                  FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
                  See Exhibit 10(a)33 herein.

         (c) 30 - Amended Unit Power Sales Agreement dated July 20, 1988,
                  between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)34 herein.

         (c) 31 - Amended Unit Power Sales Agreement dated August 17, 1988,
                  between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)35 herein.

         (c) 32 - Rocky Mountain Pumped Storage Hydroelectric Project
                  Ownership Participation Agreement dated November 18, 1988,
                  between OPC and GEORGIA. See Exhibit 10(a)36 herein.

         (c) 33 - Rocky Mountain Pumped Storage Hydroelectric Project
                  Operating Agreement dated November 18, 1988, between OPC and
                  GEORGIA. See Exhibit 10(a)37 herein.

         (c) 34 - Long Term Transaction Service Agreement between GEORGIA
                  and OPC dated as of February 26, 1999. See Exhibit 10(a)41
                  herein.

         (c) 35 - Revised and Restated Coordination Services Agreement
                  between and among GEORGIA, OPC and Georgia Systems Operations
                  Corporation dated as of September 10, 1997. See Exhibit
                  10(a)42 herein.

         (c) 36 - Amended and Restated Nuclear Managing Board Agreement for
                  Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and
                  Dalton dated as of July 1, 1993. See Exhibit 10(a)43 herein.

         (c) 37 - Integrated Transmission System Agreement, Power Sale and
                  Coordination Umbrella Agreement between GEORGIA and OPC dated
                  as of November 12, 1990. See Exhibit 10(a)44 herein.

         (c) 38 - Revised and Restated Integrated Transmission System
                  Agreement between GEORGIA and Dalton dated as of December 7,
                  1990. See Exhibit 10(a)45 herein.

         (c) 39 - Revised and Restated Integrated Transmission System
                  Agreement between GEORGIA and MEAG dated as of December 7,
                  1990. See Exhibit 10(a)46 herein.



                                      E-23
<PAGE>


         (c) 40 - Plant Scherer Managing Board Agreement dated as of
                  December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L
                  and JEA. See Exhibit 10(a)48 herein.

         (c) 41 - Plant McIntosh Combustion Turbine Purchase and Ownership
                  Participation Agreement between GEORGIA and SAVANNAH dated as
                  of December 15, 1992. See Exhibit 10(a)49 herein.

         (c) 42 - Plant McIntosh Combustion Turbine Operating Agreement
                  between GEORGIA and SAVANNAH dated as of December 15, 1992.
                  See Exhibit 10(a)50 herein.

        *(c) 43 - The Southern Company Employee Savings Plan, Amended
                  and Restated effective January 1, 2002. See Exhibit 10(a)52
                  herein.

        *(c) 44 - The Southern Company Employee Stock Ownership Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)53 herein.

       # (c) 45 - Southern Company Omnibus Incentive Compensation Plan,
                  Amended and Restated effective May 23, 2001. See Exhibit
                  10(a)54 herein.

       # (c) 46 - The Southern Company Deferred Compensation Plan,
                  Amended and Restated effective February 23, 2001. See Exhibit
                  10(a)57 herein.

       # (c) 47 - The Southern Company Outside Directors Pension Plan.
                  See Exhibit 10(a)56 herein.

       # (c) 48 - Outside Directors Stock Plan for Subsidiaries of The
                  Southern Company, Amended and Restated effective January 1,
                  2000. See Exhibit 10(a)59 herein.

         (c) 49 - The Southern Company Pension Plan, effective as of
                  January 1, 1997 and all amendments thereto through Amendment
                  Number Six. See Exhibit 10(a)60 herein.

        *(c) 50 - Amendment Number Seven to The Southern Company
                  Pension Plan. See Exhibit 10(a)61 herein.

       #*(c) 51 - The Southern Company Supplemental Executive
                  Retirement Plan, Amended and Restated effective May 1, 2000.
                  See Exhibit 10(a)62 herein.

       #*(c) 52 - The Southern Company Performance Sharing Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)63 herein.

       #*(c) 53 - The Southern Company Supplemental Benefit Plan,
                  Amended and Restated effective May 1, 2000. See Exhibit
                  10(a)64 herein.

         (c) 54 - Southern Company Change in Control Severance Plan,
                  Amended and Restated effective July 10, 2000. See Exhibit
                  10(a)65 herein.

       # (c) 55 - Southern Company Executive Change in Control
                  Severance Plan, Amended and Restated effective July 10, 2000.
                  See Exhibit 10(a)66 herein.



                                      E-24
<PAGE>


       # (c) 56 - Deferred Compensation Agreement between SOUTHERN,
                  GEORGIA and Warren Y. Jobe. See Exhibit 10(a)68 herein.

       # (c) 57 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, GEORGIA and David M. Ratcliffe. See Exhibit
                  10(a)78 herein.

       # (c) 58 - Supplemental Pension Agreement between GEORGIA and
                  Warren Y. Jobe. (Designated in GEORGIA's Form 10-K for the
                  year ended December 31, 1998, File No. 1-6468, as Exhibit
                  10(c)77.)

       #*(c) 59 - Separation Agreement between GEORGIA and Robert H.
                  Haubein, Jr. dated December 21, 2001 and First Amendment
                  thereto effective December 21, 2001.

       #*(c) 60 - Separation Agreement between GEORGIA and Fred D.
                  Williams dated December 31, 2001.

       # (c) 61 - Deferred Compensation Plan For Directors of Georgia
                  Power Company, Amended and Restated Effective February 21,
                  2001. (Designated in GEORGIA's Form 10-K for the year ended
                  December 31, 2000, File No. 1-6468 as Exhibit 10(c)71

       # (c) 62 - Southern Company Change in Control Benefit Plan
                  Determination Policy, effective July 10, 2000. See Exhibit
                  10(a)85 herein.

       # (c) 63 - Southern Company Deferred Compensation Trust
                  Agreement dated as of January 1, 2001 between Wachovia Bank,
                  N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                  SAVANNAH, Southern Communications, Energy Solutions, Mirant
                  and Southern Nuclear. See Exhibit 10(a)90 herein.

       # (c) 64 - Deferred Stock Trust Agreement for Directors of
                  SOUTHERN and its subsidiaries, dated as of January 1, 2000,
                  between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
                  GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.

       #*(c) 65 - Amended and Restated Deferred Cash Compensation
                  Trust Agreement for Directors of SOUTHERN and its
                  subsidiaries, dated as of September 1, 2001, between Wachovia
                  Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
                  SAVANNAH. See Exhibit 10 (a)92 herein.


         GULF

         (d)  1 - Service contracts dated as of January 1, 1984, between SCS
                  and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
                  and Amendment No. 1 dated as of September 6, 1985, between SCS
                  and SOUTHERN. See Exhibit 10(a)1 herein.

         (d)  2 - Interchange contract dated February 17, 2000, between
                  ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
                  See Exhibit 10(a)6 herein.



                                      E-25
<PAGE>


         (d)  3 - Plant Robert W. Scherer Unit Number Three Purchase and
                  Ownership Participation Agreement dated as of March 1, 1984,
                  Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
                  dated as of August 1, 1988, between GEORGIA and GULF. See
                  Exhibit 10(a)29 herein.

         (d)  4 - Plant Robert W. Scherer Unit Number Three Operating
                  Agreement dated as of March 1, 1984, between GEORGIA and GULF.
                  See Exhibit 10(a)30 herein.

         (d)  5 - Plant Scherer Managing Board Agreement dated as of
                  December 31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L
                  and JEA. See Exhibit 10(a)48 herein.

         (d)  6 - Unit Power Sales Agreement dated July 19, 1988, between
                  FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
                  See Exhibit 10(a)33 herein.

         (d)  7 - Amended Unit Power Sales Agreement dated July 20, 1988,
                  between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)34 herein.

         (d)  8 - Amended Unit Power Sales Agreement dated August 17, 1988,
                  between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)35 herein.

         (d)  9 - Agreement between GULF and AEC, effective August 1, 1985.
                  (Designated in GULF's Form 10-K for the year ended December
                  31, 1985, File No. 0-2429, as Exhibit 10(g).)

        *(d) 10 - The Southern Company Employee Savings Plan, Amended
                  and Restated effective January 1, 2002. See Exhibit 10(a)52
                  herein.

        *(d) 11 - The Southern Company Employee Stock Ownership Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)53 herein.

       # (d) 12 - Southern Company Omnibus Incentive Compensation Plan,
                  Amended and Restated effective May 23, 2001. See Exhibit
                  10(a)54 herein.

       # (d) 13 - The Southern Company Deferred Compensation Plan,
                  Amended and Restated effective February 23, 2001. See Exhibit
                  10(a)57 herein.

       # (d) 14 - The Southern Company Outside Directors Pension Plan.
                  See Exhibit 10(a)56 herein.

       # (d) 15 - Outside Directors Stock Plan for Subsidiaries of The
                  Southern Company, Amended and Restated effective January 1,
                  2000. See Exhibit 10(a)59 herein.

         (d) 16 - The Southern Company Pension Plan, effective as of
                  January 1, 1997 and all amendments thereto through Amendment
                  Number Six. See Exhibit 10(a)60 herein.

        *(d) 17 - Amendment Number Seven to The Southern Company
                  Pension Plan. See Exhibit 10(a)61 herein.



                                      E-26
<PAGE>



       #*(d) 18 - The Southern Company Supplemental Benefit Plan,
                  Amended and Restated effective May 1, 2000. See Exhibit
                  10(a)64 herein.

         (d) 19 - Southern Company Change in Control Severance Plan,
                  Amended and Restated effective July 10, 2000. See Exhibit
                  10(a)65 herein.

       # (d) 20 - Southern Company Executive Change in Control
                  Severance Plan, Amended and Restated effective July 10, 2000.
                  See Exhibit 10(a)66 herein.

       # (d) 21 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, GULF and Travis J. Bowden. See Exhibit
                  10(a)69 herein.

       #*(d) 22 - The Southern Company Supplemental Executive
                  Retirement Plan, Amended and Restated effective May 1, 2000.
                  See Exhibit 10(a)62 herein.

       #*(d) 23 - The Southern Company Performance Sharing Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)63 herein.

       # (d) 24 - Supplemental Pension Agreement between SAVANNAH, GULF
                  and G. Edison Holland, Jr. (Designated in GULF's Form 10-K for
                  the year ended December 31, 1998, File No. 0-2429, as Exhibit
                  10(d)35.)

       # (d) 25 - Supplemental Pension Agreement between ALABAMA, GULF
                  and Travis J. Bowden. See Exhibit 10(b)27 herein.

       # (d) 26 - Deferred Compensation Plan For Directors of Gulf
                  Power Company, Amended and Restated Effective January 1, 2000
                  and First Amendment thereto. (Designated in GULF's Form 10-K
                  for the year ended December 31, 2000, File No. 0-2429 as
                  Exhibit 10(d)33.)

       # (d) 27 - Southern Company Change in Control Benefit Plan
                  Determination Policy, effective July 10, 2000. See Exhibit
                  10(a)85 herein.

       # (d) 28 - Southern Company Deferred Compensation Trust
                  Agreement dated as of January 1, 2001 between Wachovia Bank,
                  N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                  SAVANNAH, Southern Communications, Energy Solutions, Mirant
                  and Southern Nuclear. See Exhibit 10(a)90 herein.

       # (d) 29 - Deferred Stock Trust Agreement for Directors of
                  SOUTHERN and its subsidiaries, dated as of January 1, 2000,
                  between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
                  GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.

       #*(d) 30 - Amended and Restated Deferred Cash Compensation
                  Trust Agreement for Directors of SOUTHERN and its
                  subsidiaries, dated as of September 1, 2001, between Wachovia
                  Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
                  SAVANNAH. See Exhibit 10(a)92 herein.



                                      E-27
<PAGE>


         MISSISSIPPI

         (e)  1 - Service contracts dated as of January 1, 1984, between SCS
                  and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN
                  and Amendment No. 1 dated as of September 6, 1985, between SCS
                  and SOUTHERN. See Exhibit 10(a)1 herein.

         (e)  2 - Interchange contract dated February 17, 2000, between
                  ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
                  See Exhibit 10(a)6 herein.

         (e)  3 - Unit Power Sales Agreement dated July 19, 1988, between
                  FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
                  See Exhibit 10(a)33 herein.

         (e)  4 - Amended Unit Power Sales Agreement dated July 20, 1988,
                  between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)34 herein.

         (e)  5 - Amended Unit Power Sales Agreement dated August 17, 1988,
                  between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)35 herein.

         (e)  6 - Transmission Facilities Agreement dated February 25, 1982,
                  Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated
                  December 6, 1983, between Gulf States and MISSISSIPPI. See
                  Exhibit 10(a)40 herein.

         (e)  7 - Long Term Transmission Service Agreement between Entergy
                  Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit
                  10(a)47 herein.

        *(e)  8 - The Southern Company Employee Savings Plan, Amended
                  and Restated effective January 1, 2002. See Exhibit 10(a)52
                  herein.

        *(e)  9 - The Southern Company Employee Stock Ownership Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)53 herein.

       # (e) 10 - Southern Company Omnibus Incentive Compensation Plan,
                  Amended and Restated effective May 23, 2001. See Exhibit
                  10(a)54 herein.

       # (e) 11 - The Southern Company Deferred Compensation Plan,
                  Amended and Restated effective February 23, 2001. See Exhibit
                  10(a)57 herein.

       # (e) 12 - The Southern Company Outside Directors Pension Plan.
                  See Exhibit 10(a)56 herein.

       # (e) 13 - Outside Directors Stock Plan for Subsidiaries of The
                  Southern Company, Amended and Restated effective January 1,
                  2000. See Exhibit 10(a)59 herein.

         (e) 14 - The Southern Company Pension Plan, effective as of
                  January 1, 1997 and all amendments thereto through Amendment
                  Number Six. See Exhibit 10(a)60 herein.



                                      E-28
<PAGE>


        *(e) 15 - Amendment Number Seven to The Southern Company
                  Pension Plan. See Exhibit 10(a)61 herein.

       #*(e) 16 - The Southern Company Supplemental Benefit Plan,
                  Amended and Restated effective May 1, 2000. See Exhibit
                  10(a)64 herein.

         (e) 17 - Southern Company Change in Control Severance Plan,
                  Amended and Restated effective July 10, 2000. See Exhibit
                  10(a)65 herein.

       # (e) 18 - Southern Company Executive Change in Control
                  Severance Plan, Amended and Restated effective July 10, 2000.
                  See Exhibit 10(a)66 herein.

       # (e) 19 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, MISSISSIPPI and Dwight H. Evans. See Exhibit
                  10(a)71 herein.

       #*(e) 20 - The Southern Company Supplemental Executive
                  Retirement Plan, Amended and Restated effective May 1, 2000.
                  See Exhibit 10(a)62 herein.

       #*(e) 21 - The Southern Company Performance Sharing Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)63 herein.

       # (e) 22 - Deferred Compensation Plan for Directors of
                  Mississippi Power Company, Amended and Restated Effective
                  January 1, 2000 and Amendment Number One thereto. (Designated
                  in MISSISSIPPI's Form 10-K for the year ended December 31,
                  1999, File No. 0-6849 as Exhibit 10(e)37 and in MISSISSIPPI'S
                  Form 10-K for the year December 31, 2000, File No. 0-6849 as
                  Exhibit 10(e)30.)

       # (e) 23 - Southern Company Change in Control Benefit Plan
                  Determination Policy, effective July 10, 2000. See Exhibit
                  10(a)85 herein.

       # (e) 24 - Southern Company Deferred Compensation Trust
                  Agreement dated as of January 1, 2001 between Wachovia Bank,
                  N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                  SAVANNAH, Southern Communications, Energy Solutions, Mirant
                  and Southern Nuclear. See Exhibit 10(a)90 herein.

       # (e) 25 - Deferred Stock Trust Agreement for Directors of
                  SOUTHERN and its subsidiaries, dated as of January 1, 2000,
                  between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
                  GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.

       #*(e) 26 - Amended and Restated Deferred Cash Compensation
                  Trust Agreement for Directors of SOUTHERN and its
                  subsidiaries, dated as of September 1, 2001, between Wachovia
                  Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
                  SAVANNAH. See Exhibit 10(a)92 herein.


         SAVANNAH

         (f)  1 - Service contract dated as of March 3, 1988, between SCS
                  and SAVANNAH. See Exhibit 10(a)3 herein.



                                      E-29
<PAGE>


         (f)  2 - Interchange contract dated February 17, 2000, between
                  ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH, SPC and SCS.
                  See Exhibit 10(a)6 herein.

         (f)  3 - Unit Power Sales Agreement dated July 19, 1988, between
                  FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
                  See Exhibit 10(a)33 herein.

         (f)  4 - Amended Unit Power Sales Agreement dated July 20, 1988,
                  between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)34 herein.

         (f)  5 - Amended Unit Power Sales Agreement dated August 17, 1988,
                  between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH
                  and SCS. See Exhibit 10(a)35 herein.

         (f)  6 - Plant McIntosh Combustion Turbine Purchase and Ownership
                  Participation Agreement between GEORGIA and SAVANNAH dated as
                  of December 15, 1992. See Exhibit 10(a)49 herein.

         (f)  7 - Plant McIntosh Combustion Turbine Operating Agreement
                  between GEORGIA and SAVANNAH dated December 15, 1992. See
                  Exhibit 10(a)50 herein.

        *(f)  8 - The Southern Company Employee Savings Plan, Amended
                  and Restated effective January 1, 2002. See Exhibit 10(a)52
                  herein.

        *(f)  9 - The Southern Company Employee Stock Ownership Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)53 herein.

       # (f) 10 - Southern Company Omnibus Incentive Compensation Plan,
                  Amended and Restated effective May 23, 2001. See Exhibit
                  10(a)54 herein.

       # (f) 11 - Supplemental Executive Retirement Plan of SAVANNAH,
                  Amended and Restated effective October 26, 2000. (Designated
                  in SAVANNAH's Form 10-K for the year ended December 31, 2000,
                  File No. 1-5072 as Exhibit 10(f)13.)

       # (f) 12 - Deferred Compensation Plan for Key Employees of
                  SAVANNAH, Amended and Restated effective October 26, 2000.
                  (Designated in SAVANNAH's Form 10-K for the year ended
                  December 31, 2000, File No. 1-5072 as Exhibit 10(f)14.)

       # (f) 13 - The Southern Company Outside Directors Pension Plan.
                  See Exhibit 10(a)56 herein.

       # (f) 14 - Deferred Compensation Plan for Directors of SAVANNAH,
                  Amended and Restated effective October 26, 2000. (Designated
                  in SAVANNAH's Form 10-K for the year ended December 31, 2000,
                  File No. 1-5072 as Exhibit 10(f)18.)

       # (f) 15 - Outside Directors Stock Plan for Subsidiaries of The
                  Southern Company, Amended and Restated effective January 1,
                  2000. See Exhibit 10(a)59 herein.

         (f) 16 - The Southern Company Pension Plan, effective as of
                  January 1, 1997 and all amendments thereto through Amendment
                  Number Six. See Exhibit 10(a)60 herein.



                                      E-30
<PAGE>



        *(f) 17 - Amendment Number Seven to The Southern Company
                  Pension Plan. See Exhibit 10(a)61 herein.

       #*(f) 18 - The Southern Company Supplemental Benefit Plan,
                  Amended and Restated effective May 1, 2000. See Exhibit
                  10(a)64 herein.

         (f) 19 - Southern Company Change in Control Severance Plan,
                  Amended and Restated effective July 10, 2000. See Exhibit
                  10(a)65 herein.

       # (f) 20 - Southern Company Executive Change in Control
                  Severance Plan, Amended and Restated effective July 10, 2000.
                  See Exhibit 10(a)66 herein.

       # (f) 21 - Amended and Restated Change in Control Agreement
                  between SOUTHERN, SAVANNAH and G. Edison Holland, Jr. See
                  Exhibit 10(a)75 herein.

       # (f) 22 - The Southern Company Deferred Compensation Plan,
                  Amended and Restated effective February 23, 2001. See Exhibit
                  10(a)57 herein.

       #*(f) 23 - The Southern Company Supplemental Executive
                  Retirement Plan, Amended and Restated effective May 1, 2000.
                  See Exhibit 10(a)62 herein.

       #*(f) 24 - The Southern Company Performance Sharing Plan,
                  Amended and Restated effective January 1, 2002. See Exhibit
                  10(a)63 herein.

       # (f) 25 - Supplemental Pension Agreement between SAVANNAH, GULF
                  and G. Edison Holland, Jr. See Exhibit 10(d)24 herein.

       # (f) 26 - Southern Company Change in Control Benefit Plan
                  Determination Policy, effective July 10, 2000. See Exhibit
                  10(a)85 herein.

       # (f) 27 - Agreement for supplemental pension benefits between
                  SAVANNAH and William Miles Greer. (Designated in SAVANNAH's
                  Form 10-K for the year ended December 31, 2000, File No.
                  1-5072 as Exhibit 10(f)34.)

       # (f) 28 - Agreement crediting additional service between
                  SAVANNAH and William Miles Greer. (Designated in SAVANNAH's
                  Form 10-K for the year ended December 31, 2000, File No.
                  1-5072 as Exhibit 10(f)35.)

       # (f) 29 - Southern Company Deferred Compensation Trust
                  Agreement dated as of January 1, 2001 between Wachovia Bank,
                  N.A., SOUTHERN, SCS, ALABAMA, GEORGIA, GULF, MISSISSIPPI,
                  SAVANNAH, Southern Communications, Energy Solutions, Mirant
                  and Southern Nuclear. See Exhibit 10(a)90 herein.

       # (f) 30 - Deferred Stock Trust Agreement for Directors of
                  SOUTHERN and its subsidiaries, dated as of January 1, 2000,
                  between Reliance Trust Company, SOUTHERN, ALABAMA, GEORGIA,
                  GULF, MISSISSIPPI and SAVANNAH. See Exhibit 10(a)91 herein.



                                      E-31
<PAGE>


       #*(f) 31 - Amended and Restated Deferred Cash Compensation
                  Trust Agreement for Directors of SOUTHERN and its
                  subsidiaries, dated as of September 1, 2001, between Wachovia
                  Bank, N.A, SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
                  SAVANNAH. See Exhibit 10(a)92 herein.


(21)     Subsidiaries of Registrants

         SOUTHERN

        *(a)    - Subsidiaries of Registrant is contained herein at page IV-5.

         ALABAMA

        *(b)    - Subsidiaries of Registrant is contained herein at page IV-5.

         GEORGIA

        *(c)    - Subsidiaries of Registrant is contained herein at page IV-5.

         GULF

        *(d)    - Subsidiaries of Registrant is contained herein at page IV-5.

         MISSISSIPPI

        *(e)    - Subsidiaries of Registrant is contained herein at page IV-5.

         SAVANNAH

        *(f)    - Subsidiaries of Registrant is contained herein at page IV-5.


(23)     Consents of Experts and Counsel

         SOUTHERN

        *(a)    - The consent of Arthur Andersen LLP is contained herein
                  at page IV-6.

         ALABAMA

         *(b)   - The consent of Arthur Andersen LLP is contained herein
                  at page IV-7.

         GEORGIA

         *(c)   - The consent of Arthur Andersen LLP is contained herein
                  at page IV-8.

         GULF

         *(d)   - The consent of Arthur Andersen LLP is contained herein
                  at page IV-9.



                                      E-32
<PAGE>


         MISSISSIPPI

         *(e)   - The consent of Arthur Andersen LLP is contained herein
                  at page IV-10.

         SAVANNAH

         *(f)   - The consent of Arthur Andersen LLP is contained herein
                  at page IV-11.


(24)     Powers of Attorney and Resolutions

         SOUTHERN

         *(a)   - Power of Attorney and resolution.

         ALABAMA

         *(b)   - Power of Attorney and resolution.

         GEORGIA

         *(c)   - Power of Attorney and resolution.

         GULF

         *(d)   - Power of Attorney and resolution.

         MISSISSIPPI

         *(e)   - Power of Attorney and resolution.

         SAVANNAH

         *(f)   - Power of Attorney and resolution.



                                      E-33